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TM 5-686 



TECHNICAL MANUAL 



POWER TRANSFORMER MAINTENANCE 
AND ACCEPTANCE TESTING 



APPROVED FOR PUBLIC RELEASE: DISTRIBUTION IS UNLIMITED 



HEADCtUARTERS, DEPARTMENT OF THE ARMY 



16 NOVEMBER 1998 



REPRODUCTION AUTHORIZATION/RESTRICTIONS 

This manual has been prepared by or for the Government and, except to the 
extent indicated below, is public property and not subject to copyright. 

Reprint or republication of this manual should include a credit substantially as 
follows: "Department of the Army TM 5-686, Power Transformer Maintenance 
and Acceptance Testing, 16 November 1998." 



TM 5-686 



Technical Manual 
No. 5-686 



HEADQUARTERS 

DEPARTMENT OF THE ARMY 

Washington, DC, 16 November 1998 



APPROVED FOR PUBLIC RELEASE; DISTRIBUTION IS UNLIMITED 



Power Transformer Maintenance and Acceptance Testing 



Chapter 1. INTRODUCTION/SAFETY 

Purpose 

Scope 

References 

Maintenance and testing 

Safety 

Nameplate data 

Chapter 2. CONSTRUCTION/THEORY 

Transformer applications 

Magnetic flux 

Winding, current and voltage ratios 

Core construction 

Core form construction 

Shell form construction 

Chapter 3. TRANSFORMER CONNECTIONS AND TAPS 

Tapped primaries and secondaries 

Polarity 

Autotransformers 

Single and multi-phase relationships 

Delta-wye and wye-delta displacements 

Chapter 4. COOLING/CONSTRUCTION CLASSIFICATIONS 

Classifications 

Dry-type transformers 

Liquid-filled transformers 

Tank construction 

Free breathing tanks 

Conservator tanks 

Gas-oil sealed tanks 

Automatic inert gas sealed tanks 

Sealed tank type 

CHAPTER 5. INSULATING FLUIDS 

Oil 

Oil testing 

Dissolved gas in oil analysis 

Transformer oil sampling 

Synthetics and other insulating fluids 

Chapter 6. INITIAL ACCEPTANCE INSPECTION/TESTING 

Acceptance 

Pre-arrival preparations 

Receiving and inspection 



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Paragraph Page 

Moving and storage 6-4 6-2 

Internal inspection 6-5 6-3 

Testing for leaks 6-6 6-4 

Vacuum filling 6-7 6-4 

Chapter 7. TRANSFORMER TESTING 

Test data 7-1 7-1 

Direct current testing 7-2 7-1 

Alternating current testing 7-3 7-4 

Chapter 8. TRANSFORMER AUXILIARY EQUIPMENT 

Auxiliaries 8-1 8-1 

Bushings 8-2 8-1 

Pressure relief devices 8-3 8-1 

Pressure gauges 8-4 8-3 

Temperature gauges 8-5 8-3 

Tap changers 8-6 8-4 

Lightning (surge) arresters 8-7 8-6 

Chapter 9. COMPREHENSIVE MAINTENANCE/TESTING PROGRAM 

Transformer maintenance 9-1 9-1 

Maintenance and testing program 9-2 9-1 

Documentation 9-3 9-2 

Scheduling 9-4 9-2 

Chapter 10. STATUS OF TRANSFORMER MONITORING AND DIAGNOSTICS 

Introduction 10-1 10-1 

Transformer monitoring 10-2 10-1 

Transformer diagnostics 10-3 10-3 

Conclusions 10-4 10-3 

Appendix A REFERENCES A-l 

GLOSSARY G-l 



List of Figures 



Figure 

1-1 

2-1 

2-2 

2-3 

2-4 

2-5 

2-6 

2-7 

3-1 

3-2 

3-3 

3-4 

3-5 

3-6 

3-7 

3-8 

3-9 

3-10 

3-11 

3-12 

3-13 

3-14 

4-1 

4-2 

4-3 

4-4 

6-1 

7-1 



Title Page 

Typical power transformer 1-1 

Distribution system schematic 2-1 

Transformer flux lines 2-2 

Transformer equal turns ratio 2-3 

Transformer 10:1 turns ratio 2-3 

Transformer 1:10 turns ratio 2-3 

Transformer core construction 2-4 

Transformer shell construction 2-5 

Transformer taps 3-1 

Single Phase transformer secondary winding arrangements 3-2 

Physical transformer polarity 3-2 

Diagrammatic transformer polarity 3-3 

Transformer subtractive polarity test 3-3 

Transformer additive polarity test 3-4 

Autotransformer 3-4 

Sine wave 3-5 

Three-phase sine waves 3-5 

3 phase phasor diagram 3-5 

Delta-delta and wye-wye transformer configurations 3-5 

Wye-delta and delta-wye transformer configurations 3-6 

Transformer lead markings 3-7 

Wye delta transformer nameplate 3-7 

Conservator tank transformers 4-3 

Gas-oil sealed transformers 4-3 

Automatic inert gas sealed transformers 4-3 

Sealed tank transformers 4-4 

Transformer tank vacuum filling 6-5 

Transformer maintenance test diagram 7-3 



List of Figures (continued) 

Figure Title Pa &e 

7-2 Transformer acceptance test diagram 7-3 

7-3 Winding losses in a transformer with uncontaminated dielectric 7-5 

7-4 Winding losses in a transformer with contaminated dielectric 7-5 

7-5 Voltmeter-ammeter-wattmeter method of measuring insulation power factor 7-6 

7-6 "Hot collar" bushing power factor test 7-6 

8-1 Transformer porcelain and oil filled bushings 8-2 

8-2 Mechanical pressure-relief device 8-3 

8-3 Sudden pressure relay 8-4 

8-4 Temperature gauge 8-5 

8-^5 Dial type temperature gauge 8-5 

8-6 Schematic diagram of transformer tap-changer 8-5 

8-7 Lightning arresters 8-6 

10-1 Typical failure distribution for substation transformers 10-1 

List of Tables 

Thble Title Page 

5-1 Insulating fluids: suggested test values 5-3 

5-2 Dissolved gas in oil analysis 5-4 

5-3 Troubleshooting transformers with detected gases 5-5 

10-1 Transformer gases and corresponding sources 10-2 



III 



TM 5-686 



CHAPTER 1 
INTRODUCTION/SAFETY 



1-1. Purpose 

This manual contains a generalized overview of the 
fundamentals of transformer theory and operation. 
The transformer is one of the most reliable pieces of 
electrical distribution equipment (see figure 1-1). It 
has no moving parts, requires minimal maintenance, 
and is capable of withstanding overloads, surges, 
faults, and physical abuse that may damage or destroy 
other items in the circuit- Often, the electrical event 
that burns up a motor, opens a circuit breaker, or 
blows a fuse has a subtle effect on the transformer. 
Although the transformer may continue to operate as 
before, repeat occurrences of such damaging electri- 
cal events, or lack of even minimal maintenance can 
greatly accelerate the eventual failure of the trans- 
former. The fact that a transformer continues to oper- 
ate satisfactorily in spite of neglect and abuse is a tes- 
tament to its durability. However, this durability is no 
excuse for not providing the proper care. Most of the 
effects of aging, faults, or abuse can be detected and 



corrected by a comprehensive maintenance, inspec- 
tion, and testing program. 

1-2. Scope 

Substation transformers can range from the size of a 
garbage can to the size of a small house; they can be 
equipped with a wide array of gauges, bushings, and 
other types of auxiliary equipment. The basic operating 
concepts, however, are common to all transformers. An 
understanding of these basic concepts, along with the 
application of common sense maintenance practices 
that apply to other technical fields, will provide the 
basis for a comprehensive program of inspections, 
maintenance, and testing. These activities will increase 
the transformers's service life and help to make the 
transformer's operation both safe and trouble-free. 

1-3. References 

Appendix A contains a list of references used in this 
manual. 



JQUIP LEVEL GUAGf- 



-pftMAflV BUSHINGS 




-ARRESTER 
MOUNTING 
PROVISION 



COOtASfiADWrOffS 



Figure 1-1. Typical power transformer. 



1-1 



TM 5-686 

1-4. Maintenance and testing 

Heat and contamination are the two greatest enemies to 
the transformer's operation. Heat will break down the 
solid insulation and accelerate the chemical reactions 
that take place when the oil is contaminated. All trans- 
formers require a cooling method and it is important to 
ensure that the transformer has proper cooling. Proper 
cooling usually involves cleaning the cooling surfaces, 
maximizing ventilation, and monitoring loads to ensure 
the transformer is not producing excess heat. 

a. Contamination is detrimental to the transformer, 
both inside and out. The importance of basic cleanliness 
and general housekeeping becomes evident when long- 
term service life is considered. Dirt build up and grease 
deposits severely limit the cooling abilities of radiators 
and tank surfaces. Terminal and insulation surfaces are 
especially susceptible to dirt and grease build up. Such 
buildup will usually affect test results. The transformer's 
general condition should be noted during any activity, 
and every effort should be made to maintain its integrity 
during all operations. 

b. The oil in the transformer should be kept as pure as 
possible. Dirt and moisture will start chemical reactions 
in the oil that lower both its electrical strength and its 
cooling capability. Contamination should be the primary 
concern any time the transformer must be opened. Most 
transformer oil is contaminated to some degree before it 
leaves the refinery. It is important to determine how con- 
taminated the oil is and how fast it is degenerating. 
Determining the degree of contamination is accom- 
plished by sampling and analyzing the oil on a regular 
basis. 

c. Although maintenance and work practices are 
designed to extend the transformer's life, it is inevitable 
that the transformer will eventually deteriorate to the 
point that it fails or must be replaced. Transformer test- 
ing allows this aging process to be quantified and 
tracked, to help predict replacement intervals and avoid 
failures. Historical test data is valuable for determining 
damage to the transformer after a fault or failure has 
occurred elsewhere in the circuit. By comparing test data 
taken after the fault to previous test data, damage to the 
transformer can be determined. 

1-5. Safety 

Safety is of primary concern when working around a 
transformer. The substation transformer is usually the 
highest voltage item in a facility's electrical distribution 
system. The higher voltages found at the transformer 
deserve the respect and complete attention of anyone 
working in the area. A 13.8 kV system will arc to ground 
over 2 to 3 in. However, to extinguish that same arc will 
require a separation of 18 in. Therefore, working around 
energized conductors is not recommended for anyone but 
the qualified professional. The best way to ensure safety 
when working around high voltage apparatus is to make 
absolutely certain that it is de-energized. 



a. Although inspections and sampling can usually be 
performed while the transformer is in service, all other 
service and testing functions will require that the trans- 
former is de-energized and locked out. This means that a 
thorough understanding of the transformer's circuit and 
the disconnecting methods should be reviewed before 
any work is performed. 

ft. A properly installed transformer will usually have a 
means for disconnecting both the primary and the sec- 
ondary sides; ensure that they are opened before any 
work is performed. Both disconnects should be opened 
because it is possible for generator or induced power to 
backfeed into the secondary and step up into the prima- 
ry. After verifying that the circuit is de-energized at the 
source, the area where the work is to be performed 
should be checked for voltage with a "hot stick" or some 
other voltage indicating device. 

c. It is also important to ensure that the circuit stays de- 
energized until the work is completed. This is especially 
important when the work area is not in plain view of the 
disconnect. Red or orange lock-out tags should be applied 
to all breakers and disconnects that will be opened for a 
service procedure. The tags should be highly visible, and 
as many people as possible should be made aware of their 
presence before the work begins. 

d. Some switches are equipped with physical locking 
devices (a hasp or latch). This is the best method for 
locking out a switch. The person performing the work 
should keep the key at all times, and tags should still be 
applied in case other keys exist. 

e. After verifying that all circuits are de-energized, 
grounds should be connected between all items that 
could have a different potential. This means that all con- 
ductors, hoses, ladders and other equipment should be 
grounded to the tank, and that the tank's connection to 
ground should be verified before beginning any work on 
the transformer. Static charges can be created by many 
maintenance activities, including cleaning and filtering. 
The transformer's inherent ability to step up voltages and 
currents can create lethal quantities of electricity. 

/ The inductive capabilities of the transformer should 
also be considered when working on a de-energized unit 
that is close to other conductors or devices that are ener- 
gized. A de-energized transformer can be affected by 
these energized items, and dangerous currents or volt- 
ages can be induced in the adjacent windings. 

g. Most electrical measurements require the applica- 
tion of a potential, and these potentials can be stored, 
multiplied, and discharged at the wrong time if the prop- 
er precautions are not taken. Care should be taken during 
the tests to ensure that no one comes in contact with the 
transformer while it is being tested. Set up safety barri- 
ers, or appoint safety personnel to secure remote test 
areas. After a test is completed, grounds should be left on 
the tested item for twice the duration of the test, prefer- 
ably longer. 



1-2 



TM 5-686 



h. Once the operation of the transformer is under- 
stood, especially its inherent ability to multiply volt- 
ages and currents, then safety practices can be applied 
and modified for the type of operation or test that is 
being performed. It is also recommended that anyone 
working on transformers receive regular training in 
basic first aid, CPR, and resuscitation. 

1-6, Nameplate data 

The transformer nameplate contains most of the impor- 
tant information that will be needed in the field. The 
nameplate should never be removed from the trans- 
former and should always be kept clean and legible. 
Although other information can be provided, industry 
standards require that the following information be dis- 
played on the nameplate of all power transformers: 

a. Serial number. The serial number is required any 
time the manufacturer must be contacted for informa- 
tion or parts. It should be recorded on all transformer 
inspections and tests. 

b. Class. The class, as discussed in paragraph 4-1, 
will indicate the transformer's cooling requirements 
and increased load capability. 

c. The kVA rating. The kVA rating, as opposed to the 
power output, is a true indication of the current carry- 
ing capacity of the transformer. kVA ratings for the var- 
ious cooling classes should be displayed. For three- 
phase transformers, the kVA rating is the sum of the 
power in all three legs. 

d. Voltage rating. The voltage rating should be given 
for the primary and secondary, and for all tap positions. 

e. Temperature rise. The temperature rise is the 
allowable temperature change from ambient that the 
transformer can undergo without incurring damage. 

/. Polarity (single phase). The polarity is important 
when the transformer is to be paralleled or used in con- 
junction with other transformers. 

g. Phasor diagrams. Phasor diagrams will be pro- 
vided for both the primary and the secondary coils. 
Phasor diagrams indicate the order in which the three 
phases will reach their peak voltages, and also the 



angular displacement (rotation) between the primary 
and secondary. 

h. Connection diagram. The connection diagram 
will indicate the connections of the various windings, 
and the winding connections necessary for the various 
tap voltages. 

i. Percent impedance. The impedance percent is the 
vector sum of the transformer's resistance and reac- 
tance expressed in percent. It is the ratio of the voltage 
required to circulate rated current in the corresponding 
winding, to the rated voltage of that winding. With the 
secondary terminals shorted, a very small voltage is 
required on the primary to circulate rated current on 
the secondary. The impedance is defined by the ratio of 
the applied voltage to the rated voltage of the winding. 
If, with the secondary terminals shorted, 138 volts are 
required on the primary to produce rated current Row 
in the secondary, and if the primary is rated at 13,800 
volts, then the impedance is 1 percent. The impedance 
affects the amount of current flowing through the 
transformer during short circuit or fault conditions. 

j. Impulse level (BIL). The impulse level is the crest 
value of the impulse voltage the transformer is required 
to withstand without failure. The impulse level is 
designed to simulate a lightning strike or voltage surge 
condition. The impulse level is a withstand rating for 
extremely short duration surge voltages. Liquid-filled 
transformers have an inherently higher BIL rating than 
dry-type transformers of the same kVA rating. 

k. Weight. The weight should be expressed for the 
various parts and the total. Knowledge of the weight is 
important when moving or untanking the transformer. 

I. Insulating fluid. The type of insulating fluid is 
important when additional fluid must be added or 
when unserviceable fluid must be disposed of. 
Different insulating fluids should never be mixed. The 
number of gallons, both for the main tank, and for the 
various compartments should also be noted. 

m. Instruction reference. This reference will indi- 
cate the manufacturer's publication number for the 
transformer instruction manual. 



1-3 



TM 5-686 



CHAPTER 2 
CONSTRUCTION/THEORY 



2-1 . Transformer applications 

A power transformer is a device that changes (trans- 
forms) an alternating voltage and current from one 
level to another. Power transformers are used to "step 
up" (transform) the voltages that are produced at gen- 
erators to levels that are suitable for transmission 



(higher voltage, lower current). Conversely, a trans- 
former is used to "step down" (transform) the higher 
transmission voltages to levels that are suitable for use 
at various facilities (l° wer voltage, higher current). 
Electric power can undergo numerous transformations 
between the source and the final end use point (see fig- 
ure 2-1). 



PRIMARY 



Applied 
Voltage 



f 




SECONDARY 



Induced 

Voltage 



=E> 



An alternating current circulating in the primary winding will 
induce a potential in the secondary 



Figure 2-1. Distribution system, schematic. 



a. Voltages must be stepped-up for transmission. 
Every conductor, no matter how large, will lose an 
appreciable amount of power (watts) to its resistance 
(R) when a current (I) passes through it. This loss is 
expressed as a function of the applied current 
(P=I 2 xR). Because this loss is dependent on the cur- 
rent, and since the power to be transmitted is a func- 
tion of the applied volts (E) times the amps (P=IxE), 
significant savings can be obtained by stepping the 
voltage up to a higher voltage level, with the corre- 
sponding reduction of the current value. Whether 100 
amps is to be transmitted at 100 volts (P=IxE; 100 amps 
x 100 volts = 10,000 watts) or 10 amps is to be trans- 



mitted at 1,000 volts (P=IxE; 10 amps X 1,000 volts = 
10,000 watts) the same 10,000 watts will be applied to 
the beginning of the transmission line. 

b. If the transmission distance is long enough to pro- 
duce 0.1 ohm of resistance across the transmission 
cable, P=I 2 R; (100 amp) 2 x 0.1 ohm = 1,000 watts will 
be lost across the transmission line at the 100 volt trans- 
mission level. The 1,000 volt transmission level will cre- 
ate a loss of P=I 2 R; (10 amp) 2 X 0.1 ohm = 10 watts. 
This is where transformers play an important role. 

c. Although power can be transmitted more efficient- 
ly at higher voltage levels, sometimes as high as 500 or 
750 thousand volts (kV), the devices and networks at 



2-1 



TM 5-686 



the point of utilization are rarely capable of handling 
voltages above 32,000 volts. Voltage must be "stepped 
down" to be utilized by the various devices available. 
By adjusting the voltages to the levels necessary for the 
various end use and distribution levels, electric power 
can be used both efficiently and safely. 

d. All power transformers have three basic parts, a 
primary winding, secondary winding, and a core. Even 
though little more than an air space is necessary to 
insulate an "ideal" transformer, when higher voltages 
and larger amounts of power are involved, the insulat- 
ing material becomes an integral part of the trans- 
former's operation. Because of this, the insulation sys- 
tem is often considered the fourth basic part of the 
transformer. It is important to note that, although the 
windings and core deteriorate very little with age, the 
insulation can be subjected to severe stresses and 
chemical deterioration. The insulation deteriorates at a 
relatively rapid rate, and its condition ultimately deter- 
mines the service life of the transformer. 

2-2. Magnetic flux 

The transformer operates by applying an alternating 
voltage to the primary winding. As the voltage increas- 
es, it creates a strong magnetic field with varying mag- 



netic lines of force (flux lines) that cut across the sec- 
ondary windings. When these flux lines cut across a 
conductor, a current is induced in that conductor. As 
the magnitude of the current in the primary increases, 
the growing flux lines cut across the secondary wind 
ing, and a potential is induced in thai winding. This 
inductive linking and accompanying energy transfer 
between the two windings is the basis of the trans 
former's operation (see figure 2-2). The magnetic lines 
of flux "grow" and expand into the area around the 
winding as the current increases in the primary. To 
direct these lines of flux towards the secondary, vari- 
ous core materials are used. Magnetic lines of force, 
much like electrical currents, tend to take the path of 
least resistance. The opposition to the passage of flux: 
lines through a material is called reluctance, a charac- 
teristic that is similar to resistance in an electrical cir- 
cuit. When a piece of iron is placed in a magnetic field, 
the lines of force tend to take the path of least resist- 
ance (reluctance), and flow through the iron instead of 
through the surrounding air. It can be said that the air 
has a greater reluctance than the iron. By using iron as 
a core material, more of the flux lines can be directed 
from the primary winding to the secondary winding; 
this increases the transformer's efficiency. 




An alternating current circulating in the primary winding will 
induce a potential in the secondary 



Figure 2-2. Transformer flux lines. 



2-3. Winding, current and voltage 
ratios 

If the primary and secondary have the same number of 
turns, the voltage induced into the secondary will be 
the same as the voltage impressed on the primary (see 
figure 2-3). 
a. If the primary has more turns than the secondary, 



then the voltage induced in the secondary windings will 
be stepped down in the same ratio as the number of 
turns in the two windings. If the primary voltage is 120 
volts, and there are 100 turns in the primary and 10 
turns in the secondary, then the secondary voltage will 
be 12 volts. This would be termed a "step down" trans- 
former as shown in figure 1-A. 



2-2 



TM 5-686 



INPUT 




EQUAL 
TURNS 





100 
TURNS 




Figure 2-3. Transformer equal turns ratio. 



Figure 2-5. Transformer 1:10 turns ratio. 




Figure 2—i. Transformer 10:1 turns ratio. 

ft. A "step up" transformer would have more turns on 
the secondary than on the primary, and the reverse 
voltage relationship would hold true. If the voltage on 
the primary is 120 volts, and there are 10 turns in the 
primary and 100 turns in the secondary, then the sec- 
ondary voltage would be 1200 volts. The relationship 
between the number of turns on the primary and sec- 
ondary and the input and output voltages on a step up 
transformer is shown in figure 5-2. 

c. Transformers are used to adjust voltages and cur- 
rents to the level required for specific applications. A 
transformer does not create power, and therefore 
ignoring losses, the power into the transformer must 
equal the power out of the transformer. This means 
that, according to the previous voltage equations, if the 
voltage is stepped up, the current must be stepped 
down. Current is transformed in inverse proportion to 
the ratio of turns, as shown in the following equations: 

N p (turns on primary) 



N (turns on secondary) 



E p (vo lts primary) 
E s (volts secondary) 



Ip (amperes in primary) 
L (amperes secondary) 



Ip (amperes primary) 

d. The amount of power that a transformer can han- 
dle is limited by the size of the winding conductors, and 
by the corresponding amount of heat they will product 



when current is applied. This heat is caused by losses, 
which results in a difference between the input and 
output power. Because of these losses, and because 
they are a function of the impedance rather than pure 
resistance, transformers are rated not in terms of 
power (Watts), but in terms of kVA. The output voltage 
is multiplied by the output current to obtain volt-amps; 
the k designation represents thousands. 

2-4. Core construction 

To reduce losses, most transformer cores are made up 
of thin sheets of specially annealed and rolled silicone 
steel laminations that are insulated from each other. 
The molecules of the steel have a crystal structure that 
tends to direct the flux. By rolling the steel into sheets, 
it is possible to "orient" this structure to increase its 
ability to carry the flux. 

a. As the magnetic flux "cuts" through the core mate- 
rials, small currents called "eddy currents" are induced. 
As in any other electrical circuit, introducing a. resist- 
ance (for example, insulation between the lamina- 
tions), will reduce this current and the accompanying 
losses. If a solid piece of material were used for the 
core, the currents would be too high. The actual thick- 
ness of the laminations is determined by the cost to 
produce thinner laminations versus the losses 
obtained. Most transformers operating at 60 Hertz 
(cycles per second) have a lamination thickness 
between 0.01 and 0.02 in. Higher frequencies require 
thinner laminations. 

ft. The laminations must be carefully cut and assem- 
bled to provide a smooth surface around which the 
windings are wrapped. Any burrs or pointed edges 
would allow the flux lines to concentrate, discharge 
and escape from the core. The laminations are usually 
clamped and blocked into place because bolting would 
interrupt the flow of flux. Bolts also have a tendency to 
loosen when subjected to the vibrations that are found 
in a 60 cycle transformer's core. It is important that this 



2-3 



TM 5-686 




Figure 2-6. Transformer shell construction. 



clamping arrangement remains tight; any sudden 
increase in noise or vibration of the transformer can 
indicate a loosening of the core structure. 

2-5. Core form construction 

There are two basic types of core assembly, core form 
and shell form. In the core form, the windings are 
wrapped around the core, and the only return path for 
the flux is through the center of the core. Since the core 
is located entirely inside the windings, it adds a little to 
the structural integrity of the transformer's frame. Core 
construction is desirable when compactness is a major 
requirement. Figure 2-6 illustrates a number of core 
type configurations for both single and multi-phase 
transformers. 

2-6. Shell form construction 

Shell form transformers completely enclose the wind- 
ings inside the core assembly. Shell construction is 
used for larger transformers, although some core-type 
units are built for medium and high capacity use. The 
core of a shell type transformer completely surrounds 
the windings, providing a return path for the flux lines 
both through the center and around the outside of the 
windings (see figure 2-7). Shell construction is also 
more flexible, because it allows a wide choice of wind- 
ing arrangements and coil groupings. The core can also 
act as a structural member, reducing the amount of 
external clamping and bracing required. This is espe- 
cially important in larger application where large 
forces are created by the flux. 

a. Certain wiring configurations of shell form trans- 
formers, because of the multiple paths available for the 
flux flow, are susceptible to higher core losses due to 
harmonic generations. As the voltage rises and falls at 



the operating frequency, the inductance and capaci- 
tance of various items in or near the circuit operate at 
a frequency similar to a multiple of the operating fre- 
quency. The "Third Harmonic" flows primarily in the 
core, and can triple the core losses. These losses occur 
primarily in Wye-Wye configured transformers (see 
chapter 3). 

6. The flux that links the two windings of the trans- 
former together also creates a force that tends to push 
the conductors apart. One component of this force, the 
axial component, tends to push the coils up and down 
on the core legs, and the tendency is for the coils to 
slide up and over each other. The other component is 
the longitudinal force, where the adjacent coils push 
each other outward, from side to side. Under normal 
conditions, these forces are small, but under short cir- 
cuit conditions, the forces can multiply to hundreds of 
times the normal value. For this reason, the entire coil 
and winding assembly must be firmly braced, both on 
the top and bottom and all around the sides. Bracing 
also helps to hold the coils in place during shipping. 

c. The bracing also maintains the separation that is a 
necessary part of the winding insulation, both from the 
tank walls, and from the adjacent windings. 
Nonconductive materials, such as plastic, hardwood or 
plywood blocks are used to separate the windings from 
each other and from the tank walls. These separations 
in the construction allow paths for fluid or air to circu- 
late, both adding to the insulation strength, and helping 
to dissipate the heat thereby cooling the windings. This 
is especially important in large, high voltage transform- 
ers, where the heat buildup and turn-to-turn separa- 
tions must be controlled. 

d. The windings of the transformer must be separat- 
ed (insulated) from each other and from the core, tank, 
or other grounded material. The actual insulation 



2-4 



TM 5-686 




Figure 2-7. Transformer shell construction. 



between the turns of each winding can usually be pro- 
vided by a thin enamel coating or a few layers of paper. 
This is because the entire voltage drop across the wind- 
ings is distributed proportionately across each turn. In 
other words, if the total voltage drop across a winding 
is 120 volts, and there are 100 turns in that winding, the 
potential difference between each turn is 1.2 volts 
(120/100). 

e. Transformers are designed to withstand impulse 
levels several times, and in some cases, hundreds of 
times higher than one operating voltage. This is to pro- 
vide adequate protection in the case of a lightning 
strike, a switching surge or a short circuit. By allowing 
oil to circulate between the windings, the turn-to-turn 
insulating level can be appreciably increased and the 
amount of heat built up in the windings can be effi- 
ciently dissipated. 

/ Most large power transformers have their windings 
immersed in some type of fluid. Although larger dry- 
type transformers ar constantly being produced, and 
many new forms of construction, such as resin cast and 
gas filled, are being used for power applications, the 
most common method of insulating the windings and 
dissipating the heat is by submerging the windings and 
core in an insulating fluid. Silicone, trichloroethane, 
and a wide variety of low fire point hydrocarbon based 
fluids are just a few of the fluids currently in use. This 
manual primarily applies to mineral oil-filled trans- 
formers. Although there are similarities between min- 
eral oil and many other fluids being used, the manufac- 
turer's specifications and instructions for each fluid 
should always be considered. Any reference in this 



manual to insulating, unless otherwise stated, will be 
implied to mean mineral oil. 

g. Heat must be dissipated by fluid because no trans- 
former is 100 percent efficient. There are many forms 
of losses in a transformer, and although they have dif- 
ferent sources, the resultant product of these losses is 
heat build up within the tank. Transformer losses can 
be divided into two general categories, load losses and 
no-load losses. No-load losses are independent of the 
applied load, and include core losses, excitation losses, 
and dielectric losses in the insulation. Load loses con- 
sist of the copper losses across the windings that are 
produced by the applied current (I 2 R), and of the stray 
currents in the windings that appear when the load is 
applied. These loses are usually listed by the manufac- 
turer for each type of transformer. They are especially 
important when considering the cooling requirements 
of the transformer. 

h. Some of the important transformer equations are 
as follows: 
Basic transformer ratio: 



N p (# turns primary) 
N s (# turns secondary) 


E p (volts primary) 
E s (volts secondary} 


Current equation: 




IpXN p = ] 


s x N s 


Percent efficiency: 




output X 100% 
input 


output X 1009<) 
output + losses 



2-5 



TM 5-686 



CHAPTER 3 
TRANSFORMER CONNECTIONS AND TAPS 



3-1. Tapped primaries and 
secondaries 

To composite for changing input voltages, multiple 
connections or "taps" are provided to allow different 
portions of the winding to be used. When the taps are 
connected on the primary winding, the turn-to-turn 



ratio is changed, and the required secondary voltage 
can be obtained in spite of a change in source voltage. 
Manufacturers usually provide taps at 2-1/2 percent 
intervals above and below the rated voltage (see figure 
3-1) Taps at 2.5 percent allow the number of turns on 
the primary to change. 



Hj (RATED VOLTAGE) 




X j (RATED VOLTAGE) 



Figure 3-1. Transformer taps. 



a. Taps are usually changed by turning a crank or 
hand-wheel, although some transformers require that a 
cover be removed and the actual winding leads be con- 
nected on a terminal board where all of the taps can be 
accessed. Tap changers can be either "Load Tap 
Changing" or "No-Load Tap (N.L.T.) Changing" units, 
although most of them must be changed with the trans- 
former de-energized. 

6. Smaller single-phase transformers are usually pro- 
vided with center-tapped secondaries, with the leads 
brought out from both halves of the tapped winding. 
When the center tap leads are connected together, that 
winding becomes one continuous coil, and it is said to 
be connected in series (see figure 3-2). Because the 
maximum number of turns are used, the maximum 
voltage is obtained, at the corresponding current level. 

c. When the center taps are connected to the oppo- 
site output leads, the winding becomes two separate 
windings working in parallel (see figure 3-2). A lower 
voltage at a corresponding higher current level is 
obtained. 



3-2. Polarity 

Note that, when the center tap is connected in parallel, 
both windings are oriented in the same direction with 
respect to the primary. The clockwise or counterclock- 
wise direction that the windings are wound on the core 
determine the direction of the current flow (the 
right-hand rule). This relationship of winding orienta- 
tion to current flow in the transformer is known as 
polarity. 

a. The polarity of a transformer is a result of the rel- 
ative winding directions of the transformer primary 
conductor with respect to the transformer secondary 
(see figure 3-3). Polarity is a function of the trans- 
former's construction. Polarity becomes important 
when more than one transformer is involved in a cir- 
cuit. Therefore, the polarities and markings of trans- 
formers are standardized. Distribution Transformers 
above 200 KVA or above 860 volts are "subtractive." 

b. Transformer polarity is an indication of the direc- 
tion of current flow through the high-voltage terminals, 



3-1 



TM 5-686 




230 VOLTS 

A 



115 VOLTS 
B 



Figure 3-2. Single phase transformer secondary winding arrangenumis. 



with respect to the direction of current flow through 
the low-voltage terminals at any given instant in the 
alternating cycle. Transformers are constructed with 
additive or subtractive polarity (see figures 3-4). The 
terminal markings on transformers are standardized 
among the various manufacturers, and are indicative of 
the polarity. However, since there is always the possi- 
bility that the wiring of a transformer could have been 
changed, it is important to check the transformer's 
polarity before making any wiring changes. 

c. The polarity is subtractive when the high-side lead 
(HI) is brought out on the same side as the low-side 
lead (XI). If a voltage is placed on the high-side, and a 
jumper is connected between the HI and XI terminals 
(see figure 3-5), the voltage read across the H2 and X2 
terminals will be less than the applied voltage. Most 
large power transformers are constructed with sub- 
tractive polarity. 

d. When the high-side lead (HI) is brought out on the 
opposite side of the low-side lead (XI) and is on the 
same side as the low side lead (X2), the polarity is addi- 
tive. If a voltage is placed across the high-side, and a 



jumper is connected between the HI and X2 terminals, 
the voltage read across the H2 and XI terminals will be 
greater than the applied voltage (see figure 23-6). 

3-3. Autotransformers 

Although the examples illustrated up to this point have 
used two separate windings to transform the voltage 
and current, this transformation can be accomplished 
by dividing one winding into sections. The desired 
ratio can be obtained by "tapping" the winding at a 
prescribed point to yield the proper ratio between the 
two sections. This arrangement is called an "Auto- 
transformer." 

a. Even though the winding is continuous, the 
desired voltages and currents can be obtained. 
Although an autotransformer is made up of one contin- 
uous winding, the relationship of the two sections can 
be more readily understood if they are thought of as 
two separate windings connected in series. Figure 3-7 
shows the current and voltage relationships in the var- 
ious sections of an autotransformer. 

b. Autotransformers are inherently smaller than nor- 



H i H s 




SUBTRACTIVE POLARITY 



x 2 


| H i H a 


x i 




i* 


• 


i 


|4 
1 - 

j ^ 




i 



ADDITIVE POLARSTY 



Figure 3—8. Physical, transformer polarity. 



3-2 



TM 5-686 



H, -Hj 


H : — H 


£ 


• 




^ 


* 

c 




^ 


K 




J 


K 




j 


* 


l " 


3 


X 


2 — » 


1 


SUBTRACTIVE POLARITY 


ADDITIVE POLAK1TY 



Figure 3-4. Diagrammatic transformer polarity. 

mal two-winding transformers. They are especially 
suited for applications where there is not too much dif- 
ference between the primary and secondary voltages 
(transformer ratios usually less than 5:1). An auto- 
transformer will have lower losses, impedance, and 
excitation current values than a two-winding trans- 
former of th same KVA rating because less material is 
used in its construction. 

c. The major drawback of autotransformers is that 
they do not provide separation between the primary 
and secondary. This non-insulating feature of the auto- 
transformer should always be remembered; even 
though a low voltage may be tapped from an auto- 
transformer, the low voltage circuit must be insulated 
to the same degree as the high voltage side of the trans- 
former. Another drawback is that the autotransformer's 
impedance is extremely low, and it provides almost no 
opposition to fault current. Autotransformers are usu- 
ally primarily for motor staring circuits, where lower 
voltages are required at the start to reduce the amount 
of inrush current, and higher voltages are used once the 
motor is running. Autotransformers are used in power 



applications where the difference between the primary 
and secondary voltages is not too great. 

3-4. Single and multi-phase 
relationships 

All transformations occur on a single-phase basis; 
three-phase transformers are constructed by combin- 
ing three single-phase transformers in the same tank. 
As indicated by its name, a single-phase transformer is 
a transformer that transforms one single-phase voltage 
and current to another voltage and current level. 

a. Alternating current single-phase power can be rep- 
resented by a graph of constantly changing voltage ver- 
sus time (a sine wave). The potential changes continu- 
ously from positive to negative values over a given time 
period. When the voltage has gone through one com- 
plete series of positive and negative changes, it is said 
to have completed one cycle. This cycle is expressed in 
degrees of rotation, with 360 degrees representing one 
full cycle. As shown in figure 3-8 a start point is desig- 
nated for any sine wave. The sine wave position and 
corresponding voltage can be expressed in degrees of 
rotation, or degrees of displacement from the starting 
point. 

b. This alternating voltage can be readily produced 
by rotating generators, and in turn can be easily utilized 
by motors and other forms of rotating machinery. 
Single-phase power is used primarily in residential or 
limited commercial applications. 

c. Most industrial or institutional systems utilize a 
three-phase power configuration. Three single-phase 
lines are used (A, B and C), and it is only when they are 
connected to an end use device, such as a motor or 
transformer that their relationships to each other 
become important. By convention, the individual phas- 



Ik, 



6 O 

9 



-©■ 



o 6 

9 9 



"' 






SUBTRACTIVE POLARITY. THE Hi AND XI LEADS ARE ON THE SAME SIDE 
VOLTAGE READ AT VOLTMETER V IS LESS THAN THE APPLIED VOLTAGE. 



Figure 3-5. Transformer subtractive polarity test. 



3-3 



TM 5-686 



I 

— i ,_ 

6 o 

O Q 



-o- 



6 6 
o o 







ADDITIVE POLARITY. THE H-l AND X- 1 LEADS ARE NOT ON THE SAME SIDE 



Figure 3-6. Transformer additive polarity test. 



es of a three-phase distribution system are displaced 
120 degrees (one third of a cycle) apart (see figure 3-9). 

d. Rather than draw sine waves to show the position 
of the phases, the relative angular displacement 
(degrees ahead of or later than) is depicted by phasor 
diagrams. Phasor diagrams are convenient because 
they not only show the angular displacement, but they 
also show how the phases are physically connected. 
Transformer manufacturers use phasor diagrams on 
the nameplate of the transformer to indicate the con- 
nections and angular displacement of the primary and 
secondary phases (see figure 3-10). The polarity of 
three-phase transformers is determined both by where 
the leads are brought out of the transformer, and by the 
connection of the phases inside the tank. The two most 
common connections for three-phase transformers are 
delta and wye (star). 

e. Delta and wye are the connections and relations of 
the separate phase on either the primary or the sec- 



ondary windings. The basic three-phase transformer 
primary-to-secondary configurations are as follows: 

-Delta-delta -Delta-wye 

-Wye-wye -Wye-delta 

/ These configurations can be obtained by connect- 
ing together three single-phase transformers or by com- 
bining three single-phase transformers in the same 
tank. There are many variations to these configura- 
tions, and the individual transformer's design and appli- 
cation criteria should be considered. 

g. The wye connection is extremely popular for use 
on the secondary of substation transformers. By con- 
necting the loads either phase-to-phase or phase-to- 
neutral, two secondary voltages can be obtained on the 
secondary. A common secondary voltage on many dis- 
tribution transformers is 208/120V, with the 208V 
(phase-to-phase) connections being used to supply 
motors, and the 120V (phase-to-neutral) connections 



20 TURNS 

120 VOLTS 

10 AMPS 




5 TURNS 
30 VOLTS 
40 AMPS 




Autotrnnsformers use dub continuous winding- The entire winding must be constructed to handle 
higher secondary current(40A) and the higher primary voltage fl20V) 



Figure 3-7. Autotransformer. 



3-4 



TM 5-686 



PUSH 












PULL 


90 \ 


. 180 / 


' avo 


i 




ONE REVOLUTION 






OR ONE CYCLE 




i 



Figure 3-8. Sine wave. 



PUSH 
PULL 


A 

/ X 1 


— 1ZO *- 




c 




/fT 


^-~^_ 


SO \ 


/ 180 \ 

ONE REVOLUTIO 
OR ONE CYCLE 


U 


270 \ 


M 











Figure 3-9. Three phase sine waves. 

being used to supply lighting loads (see figure 3-11). 
These secondary voltages are related by the square 
root of three (1.73). As shown in figure 3-11, this con- 
figuration provides an added degree of flexibility. 

h. Often, when ground fault is desired for certain cir- 
cuits, the neutral will be isolated and carried through- 
out the circuit (except at the system ground point, usu- 
ally the wye-grounded secondary transformer 




Figure 3-10. Three phase phasor diagram. 

connection) providing an isolated return path for load 
currents. This provides an opportunity to monitor these 
currents and to open the circuit in the event of a ground 
fault. Although the neutral is eventually grounded, it is 
isolated for the portion of the circuit where ground fault 
protection is needed (usually in the switchgear between 
the transformer secondary and the individual circuit 
breakers). It is important in these configurations to 
maintain the isolation of the neutral conductor. The 
common practice of bonding neutrals to ground at 



DELTA PRCMARY 







I 


LUJJL r bUUUUo H 

X2 X3 


uuuxu 


1 1 

-J 1 


,L f 


i ■ *™ i *i° 


■r I 


. '" : i — i. - 





DELTA SECONDARY 



.£: 



A 



Y-PKlMARY (4 KTKE) 






HI HJf— ?—• J 

LbjjjuU Ljuxsuu uuuuju 



rxxn 



- t ' I I - 



^ 




Y-SECONDARY (* WIRE) 



ANGULAR 
DISPLACEMENT 



Figure 3-11. Delta-delta and wye-wye transformer configurations. 



3-5 



TM 5-686 



every possible point can defeat this protective scheme 
and render ground fault protection inoperative. 

i. When the neutral conductor is grounded, it pro- 
vides s stabilizing effect on the circuit. With the neutral 
point solidly grounded, the voltage of any system con- 
ductor, with respect to ground, cannot exceed the 
phase-to-phase voltage. Without grounding the neutral, 
any stable ground fault on one line raises the voltage of 
the two remaining lines with respect to ground, to a 
point as high as the phase-to-phase voltage. The impli- 
cations are obvious; there will be less stress placed on 
the system insulation components with the wye- 
grounded connection. 

3-5. Delta-wye and wye-delta 
displacements 

As current and voltage are transformed in the individ- 
ual phases of a wye-delta or delta-wye transformer, 
they can also have an angular displacement that occurs 
between the primary and secondary windings. That is, 
the primary wave-form of the A phase at any given 
instant is always 30 degrees ahead of or displaced from 
the wave form of the A phase on the secondary. This 30 
degree shift occurs only between the primary and sec- 
ondary and is independent of the 120 degrees of dis- 
placement between the other phases. 

a. By convention, delta-delta and wye-wye trans- 
formers have zero degrees angular displacement 
between primary and secondary. See the phasor dia- 
grams in figure 3-11. The individual wave forms 
between the primary and secondary are identical at any 
given instant. Delta-wye and wye-delta transformers 
have an angular displacement of 30 degrees. For these 
types of connections, the high-voltage reference phase 
angle side of the transformer is 30 degrees ahead of the 
low-voltage reference phase angle at any given instant 



for each individual phase. This displacement is repre- 
sented on the transformer's nameplate by a rotation of 
the phasor diagrams between the primary and sec- 
ondary. See the phasor diagrams in figure 3-12. 

6. Most manufacturers conform to American 
National Standards Institute (ANSI) Standard 
C57.12.70, "Terminal markings for Distribution and 
Power Transformers' (R1993), for the lead markings of 
larger (subtractive polarity) three-phase power trans- 
formers. The high-voltage lead, III is brought out on 
the right side when facing the high voltage side of the 
transformer case. The remaining high-voltage leads H2 
and H3 are brought out and numbered in sequence 
from right to left. The low-voltage lead, XI is brought 
out on the left side (directly opposite the HI terminal) 
when facing the low side of the transformer. The 
remaining leads, X2 and X3 are numbered in sequence 
from left to right (see figure 3-13). It is important to 
note that these are suggested applications, and design 
constraints can require that a transformer be built with 
different markings. It is also important to remember 
that in many existing installations, there is the possibil- 
ity that the leads have been changed and do not con- 
form to the standardized markings. 

c. Figure 3-14 shows the standard delta-wye three- 
phase transformer's nameplate illustrating many of the 
topics covered in this chapter. The various primary tap 
voltages, along with the numbered coimection points 
on the actual windings are referenced in the 
"Connections" table. The wiring diagram shows the 
relationship and connections of the individual wind- 
ings, while the phasor diagrams show the phase angle 
relationship between the individual phases, and 
between the primary and secondary. Note also that the 
temperature requirements, the tank pressure capabili- 
ties, and the expansion and contraction-versus-temper- 
ature values are spelled out. 



Y-PRIMARY (UNGROUNDED) 



A J- 

B ! 



i hi I ma 

UOAAJU UUULSJU 



nrm orrn 



XI,- 






X3 



H3 

mm. 







1 


ISO 






« *"■ 


f I 


L 

3* a 


j 


I 




DELTA SECONDARY 
b 



30 ANGULAR 
DISPLACEMENT 



DELTA PRIMARY 




n 



UULEJUU 



I 



I 

„JL_ 



— 1 

2» 



Y-SECONDARY (4 WIRE) 
b 




30 ANGULAR 
DISPLACEMENT 



Figure 3-12. Wye-delta and delta-wye transformer configuration. 



3-6 



TM 5-686 



HO 
H3 



rl 



D> 



^ 



Hi' |H1^ ^H3 ^X3l)Xl HI 



< 



xa M^ H2[ 



/XE 



H]X4 H3[^ 
5 



h1 Ah3 X1 ^- X3 X ° >! HlC «^ H3 ^ 



H2 X2 ^ 

i X 3 



HO HI H2 H3 



H2 H3 — , 






HI H2 H3 — | V4 

©©© f> 

xa rixs 
x ° t. 

X3 _J X1 



A >"-(- 

H1 Z iH3 \ 



HI HE H3 



>1 

ID x3 



H2 xa )_J xa 

n^ — -»H3 Xl^ — -*> 



J' 



Figure 3-13. Transformer lead markings. 



o 



TRANSFORMER 



O 



SERIAL NO. 940732.B CLASS OA/FFA THREE PHASE 60 HERTZ 



HV VOLTS 13800GY/7970 

LV VOLTS 4160 DELTA 

KVA RATING 3750 CONTINUOUS 65 

IMPEDANCE MIN 7.00% AT 3750 



MFG. DATE 
C RISE 
KVA 



HV WINDING CONNECTIONS 


AMPS 






VOLTS | 3750 


TAP 


CONNECTS 


H1-H2-H3; KVA 






14490 ' 149.4 


A 


1 TO 2 


14145 : 153.0 


B 


2 OF 3 


13800 i 156.9 


C 


3 TO 4 


13455 j 160.9 


D 


4 TO 5 


13110 i 165.1 


E 


5 TO 6 


-- i — 


F 


6 TO 7 


-- j G | 7 TO 6 


CAUTION: 


DE-ENERGIZE TRANSFORMER 


BEFORE CHANGING TAPS 



WINDING MATERIAL 


HV 


CU 


LV 


CU 



LV WINDING CONNECTIONS 



VOLTS 
X1-X2-X3 



4160 



AMPS 
3750 KVA 



520.4 



BIL LEVELS 




HV WINDING 


95 KV 


HV NEUTRAL 


95 KV 


HV NEUTRAL BUSHING 


95 KV 


LV WINDING 


60 KV 



LIQUID TYPE OIL CONTAINS LESS THAN 1 PPM OF PCB 

FLUID AT TIME OF MANUFACTURE. LIQUID LEVEL BELOW TOP OF 
MANHOLE FLANGE AT 25 C IS 216 MILLIMETERS LIQUID LEVEL 
CHANGES 11.00 MM PER 10 C CHANGE IN LIQUID TEMPERATURE. 
MAXIMUM OPERATING PRESSURES OF LIQUID PRESERVATION SYSTEM 
68.95kPa POSITIVE AND 55.16kPa NEGATIVE. TANK SUITABLE 
FOR 48.26kPa VACUUM FILLING. 



APPROXIMATE WEIGHTS IN POUNDS 
2498 LITERS LIQ. 2245 KGS TANK & FITTINGS 2012 KGS 
CORE & COILS 3824 KGS TOTAL 8038 KGS 



CAUTION": BEFORE INSTALLING OR OPERATING READ INSTRUCTION- 
BOOK 43500-054-04 _ 

O o 

MADE IN U.S.A. 



Figure 3-14. Wye delta transformer nameplate. 



3-7 



TM 5-686 



CHAPTER 4 
COOLING/CONSTRUCTION CLASSIFICATIONS 



4-1. Classifications 

Although transformers can be classified by core con- 
struction (shell or core type), the more functional types 
of standardized classifications are based on how the 
transformer is designed for its specific application, and 
how the heat created by its losses is dissipated. There 
are several types of insulating media available. Two 
basic classifications for insulating media are dry-type 
and liquid filled. 

4-2. Dry-type transformers 

Dry-type transformers depend primarily on air circula- 
tion to draw away the heat generated by the trans- 
former's losses. Air has a relatively low thermal capac- 
ity. When a volume of air is passed over an object that 
has a higher temperature, only a small amount of that 
object's heat can be transferred to the air and drawn 
away. Liquids, on the other hand, are capable of draw- 
ing away larger amounts of heat. Air cooled transform- 
ers, although operated at higher temperatures, are not 
capable of shedding heat as effectively as liquid cooled 
transforms. This is further complicated by the inherent 
inefficiency of the dry-type transformer. Transformer 
oils and other synthetic transformer fluids are capable 
of drawing away larger quantities of excess heat. 

a. Dry-type transformers are especially suited for a 
number of applications. Because dry-type transformers 
have no oil, they can be used where fire hazards must 
be minimized. However, because dry-type transformers 
depend on air to provide cooling, and because their 
losses are usually higher, there is an upper limit to their 
size (usually around 10,000 kVA, although larger ones 
are constantly being designed). Also, because oil is not 
available to increase the dielectric strength of the insu- 
lation, more insulation is required on the windings, and 
they must be wound with more clearance between the 
individual turns. 

b. Dry-type transformers can be designed to operate 
at much higher temperatures than oil-filled transform- 
ers (temperature rises as high s 150 °C). Although oil is 
capable of drawing away larger amounts of heat, the 
actual oil temperature must be kept below approxi- 
mately 100 °C to prevent accelerated breakdown of the 
oil. 

c. Because of the insulating materials used (glass, 
paper, epoxy, etc.) and the use of air as the cooling 
medium, the operating temperatures of dry-type trans- 



formers are inherently higher. It is important that ade- 
quate ventilation be provided. A good rule of thumb is 
to provide at least 20 square feet of inlet and outlet ven- 
tilation in the room or vault for each 1,000 kVA of trans- 
former capacity. If the transformer's losses are laiown, 
an air volume of 100 cfm (cubic feet per minute) for 
each kW of loss generated by the transformer should 
be provided. Dry-type transformers can be either self- 
cooled or forced-air cooled. 

d. A self-cooled dry-type transformer is cooled by the 
natural circulation of air through the transformer case. 
The cooling class designation for this transfonner is 
AA. This type of transformer depends on the convec- 
tion currents created by the heat of the transfoi-mer to 
create an air flow across the coils of the transformer. 

e. Often, fans will be used to add to the circulation of 
air through the case. Louvers or screened openings are 
used to direct the flow of cool air across the trans- 
former coils. The kVA rating of a fan-cooled dry-type 
transformer is increased by as much as 33 percent over 
that of a self-cooled dry-type of the same design. The 
cooling class designation for fan cooled or air blast 
transformers is FA. Dry-type transformers can be 
obtained with both self-cooled and forced air-cooled 
ratings. The designation for this type of transformers is 
AA/FA. 

/ Many other types of dry-type transformers are in 
use, and newer designs are constantly being developed. 
Filling the tank with various types of inert gas or casting 
the entire core assemblies in epoxy resins are just a few 
of the methods currently is use. Two of the advantages 
of dry-type transformers are that they have no fluid to 
leak or degenerate over time, and that they present 
practically no fire hazard. It is important to remember 
that dry-type transformers depend primarily on their 
surface area to conduct the heat away from to core. 
Although they require less maintenance, the core and 
case materials must be kept clean. A thin layer of dust 
or grease can act as an insulating blanket, and severely 
reduce the transformer's ability to shed its heat. 

4-3. Liquid-filled transformers 

Liquid-filled transformers are capable of handling larg- 
er amounts of power. The liquid (oil, silicone, PCB etc.) 
transfers the heat away from the core more effectively 
than air. The liquid can also be routed away from the 
main tank, into radiators or heat exchangers to further 
increase the cooling capacity. Along with cooling the 



4-1 



TM 5-686 



transformer, the liquid also acts as an insulator. Since 
oils and synthetics will break down and lose their insu- 
lating ability at higher temperatures, liquid filled trans- 
formers are designed to operate at lower temperatures 
than dry-types (temperature rises around 55 °C). Just 
as with dry-types, liquid-filled transformers can be self- 
cooled, or they can use external systems to augment 
the cooling capacity. 

a. A self-cooled transformer depends on the surface 
area of the tank walls to conduct away the excess heat. 
This surface area can be increased by corrugating the 
tank wall, adding fins, external tubing or radiators for 
the fluid. The varying heat inside the tank creates con- 
vection currents in the liquid, and the circulating liquid 
draws the heat away from the core. The cooling class 
designation for self-cooled, oil-filled transformers is OA 

b. Fans are often used to help circulate the air 
around the radiators. These fans can be manually or 
automatically controlled, and will increase the trans- 
former's kVA capacity by varying amounts, depending 
on the type of construction. The increase is usually 
around 33 percent, and is denoted on the transformer's 
nameplate by a slash (/) rating. Slash ratings are deter- 
mined by the manufacturer, and vary for different 
transformers. If loading is to be increased by the addi- 
tion of pumps or fans, the manufacturer should be con- 
tacted. The cooling class designation for a forced air- 
cooled, oil-filled transformer is OA/FA. 

c. Pumps can be used to circulate the oil in the tank 
and increase the cooling capacity. Although the con- 
vection currents occur in the tank naturally, moving the 
oil more rapidly past the radiators and other heat 
exchangers can greatly increase their efficiency. The 
pumps are usually installed where the radiators join the 
tank walls, and they are almost always used in con- 
junction with fans. The cooling class designation for 
forced oil and forced air cooled transformers is 
OA/FA/FOA. 

d. To obtain improved cooling characteristics, an 
auxiliary tubing system is often used to circulate water 
through the transformer's oil. This type of design is 
especially suited for applications where sufficient air 
circulation cannot be provided at the point of installa- 
tion, such as underground, inside of buildings, or for 
specialized applications in furnace areas. Because 
water is used to draw off the heat, it can be piped to a 
remote location where heat exchangers can be used to 
dissipate the heat. In this type of construction, tubing is 
used to circulate water inside the tank. The tubing cir- 
culates through the oil near the top, where it is the 
hottest; great pains must be taken to ensure that the 
tubing does not leak, and to allow the water to mix with 
the oil. Water is especially desirable for this applica- 
tion because it has a higher thermal capacity than oil. If 
untreated water is used, steps must be taken to ensure 
that the pipes do not become clogged by contaminants, 
especially when hard water is used. The cooling class 
designation for water-cooled transformers is FOW. 



4^4. Tank construction 

Transformers can also be classified according to tank 
construction. Although the ideal transformer is a static 
device with no moving parts, the oil and the tank itself 
are constantly expanding and contracting, or "breath- 
ing," according to the changing temperatures caused by 
the varying load of the transformer. 

a. When the oil is heated, it expands (0.08 percent 
volume per °C) and attempts to force air out of the 
tank. Thermal expansion can cause the oil level in the 
tank to change as much as 5 or 6 inches, depending on 
the type of construction. This exhaust cycle causes no 
harm. It is on the contraction cycle that outside air can 
be drawn into the tank, contaminating the oil. 

b. When oxygen and moisture come in contact with 
oil at high temperatures, the oil's dielectric strength is 
reduced, and sludge begins to form. Sludge blocks the 
flow of oil in the tank and severely reduces the trans- 
former's cooling capacity. Various types of tank con- 
struction are utilized to accommodate the trans- 
former's expansion and contraction cycles while 
preventing the oil from being contaminated. 

4-5. Free breathing tanks 

Free-breathing tanks are maintained at atmospheric 
pressure at all times. The passage of outside air is 
directed through a series of baffles and filters. 
Dehydrating compounds (such as calcium chloride or 
silica gel) are often placed at the inlet to prevent the oil 
from being contaminated. Free breathing transformers 
substantially reduce the pressure forces placed on the 
tank, but are not very effective at isolating the oil. Even 
if the moisture is removed, the air will still contain oxy- 
gen and cause sludging. Also, if the dehydrating com- 
pounds are not replaced regularly, they can become 
saturated and begin "rehydrating" the incoming air and 
adding moisture to the oil. 

4-6. Conservator tanks 

Conservator or expansion type tanks use a separate 
tank to minimize the contact between the transformer 
oil and the outside air (see figure 4-1). This conserva- 
tor tank is usually between 3 and 10 percent of the 
main tank's size. The main tank is completely filled 
with oil, and a small conservator tank is mounted 
above the main tank level. A sump system is used to 
connect the two tanks, and only the conservator tank is 
allowed to be in contact with the outside air. 

a. By mounting the sump at a higher level in the con- 
servator tank, sludge and water can form at the bottom 
of the conservator tank and not be passed into the main, 
tank. The level in the main tank never changes, and the 
conservator tank can be drained periodically to remove 
the accumulated water and sludge. Conservator tank 
transformers often use dehydrating breathers at the 
inlet port of the conservator tank to further minimize 
the possibility of contamination. 



4-2 



TM 5-686 




CONSERVATOR TANK TRANSFORMERS 
USE AN AUXILIARY TANK TO 
ACCOMODATE THE TRANSFORMER'S 
EXPANSION AND CONTRACTION 
WITHOUT CONTAMINATING THE 

Main tank's OIL 



Figure 4-1. Conservator tank transformers. 

b. Although this design minimizes contact with the 
oil in the main tank, the auxiliary tank's oil is subjected 
to a higher degree of contamination because it is mak- 
ing up for the expansion and contraction of the main 
tank. Dangerous gases can form in the head space of 
the auxiliary tank, and extreme caution should be exer- 
cised when working around this type of transformer. 
The auxiliary tank's oil must be changed periodically, 
along with a periodic draining of the sump. 

4-7. Gas-oil sealed tanks 

The gas-oil sealed tank is similar to the conservator 
tank, in that an auxiliary tank is used to minimize the 
oil's contact with the atmosphere (see figure 4-2). 
However, in this type of design, the main tank oil never 
actually comes in contact with the auxiliary tank's oil. 
When the main tank's oil expands and contracts, the 
gas in the head space moves in and out of the auxiliary 
tank through a manometer type set-up. The auxiliary 
tank is further divided into two sections, which are also 
connected by a manometer. The levels of both sections 
of the auxiliary tank and main tank can rise and fall 
repeatedly, and the main tank's oil will never come in 
contact with the outside atmospheres. The oil in the 
auxiliary tank is subject to rapid deterioration, and just 
as in the conservator type, gases and potent acids can 
form in the auxiliary tank if the oil is not drained and 
replaced periodically. 

4-8. Automatic inert gas sealed tanks 

Some transformers use inert gas systems to complete- 
ly eliminate contamination (see figure 4-3). These sys- 
tems are both expensive and complicated, but are very 




CAS -OIL SEALED UNITS USE TWO TANKS 
TO FUFTHEH EUMTNATE CONTAMINATION 



Figure 4-2. Gas-oil sealed transformers. 

effective. The pressure in the tank is allowed to fluctu- 
ate within certain levels (+/- 5 psi), and any excess 
pressure is simply bled off into the atmosphere. When 
the transformer cools and begins its intake cycle, the 
in-going gas is supplied from a pressurized nitrogen 
bottle. Nitrogen gas has little detrimental effect on the 
transformer oil and is not a fire or explosion hazard. 
Inert gas systems (sometimes called pressurized gas 
systems) have higher initial installation costs, and 
require more periodic attention throughout their life 
than non-pressurized gas systems. 




AUTOMATIC INERT GAS UNITS ELIMINATE CONTAMINATION 
BY USING PRESSLRIZED GAS ON THE INTAKE CYCLE 



Figure 4-3. Automatic inert gas sealed transformers. 



4-3 



TM 5-686 



4-9. Sealed tank type 

Sealed tank units (see figure 4-4) are the most common 
type of construction. The tank is completely sealed and 
constructed to withstand a moderate amount of con- 
traction and expansion (usually +/- 5 psi). This pres- 
sure difference will usually cover the fluctuations the 
transformer will undergo during normal operation. 

a. A gas blanket, usually nitrogen, is placed over the 
oil in the main tank and this "cushion" helps to absorb 
most of the forces created by the pressure fluctuations. 
A slight pressure (around 1 psi) is maintained on the 
tank to prevent any unwanted influx of air or liquid. 
The higher pressures caused by severe overloading, 
arcing, or internal faults are handled by pressure relief 
devices. 

b. There are many auxiliary systems and devices that 
are used to maintain the integrity of the tank's seal and 
to compensate for any extreme or unplanned condi- 
tions. There are also a number of gauges and relays 
which are covered in chapter 9 that are used to moni- 
tor the pressure and temperature conditions inside the 
tank. 




SEALED TANK CONSTRUCTION IS THE MOST COMMON. 
AND REQUIRES STRONGER TANK WALLS ALONG WITH A 
GAS CUSHION AT THE TOP TO ABSORB THE STRESS 



Figure 4-ty. Sealed transformers. 



TM 5-686 



CHAPTER 5 
INSULATING FLUIDS 



5-1. Oil 

Although new systems are fluids are constantly being 
developed, mineral oil is the most common fluid in use 
today. Polychlorinated biphenyl (PCBs) are not accept- 
able to the Environmental Protection Agency (EPA) for 
use in transformers. Any reference to "oil" or "insulat- 
ing fluid" in this section will be understood to mean 
transformer mineral oil. The manufacturer's instruc- 
tions and guidelines should be considered when deal- 
ing with fluids. 

a. Insulating fluid plays a dual function in the trans- 
former. The fluid helps to draw the heat away from the 
core, keeping temperatures low and extending the life 
of the insulation. It also acts as a dielectric material, 
and intensifies the insulation strength between the 
windings. To keep the transformer operating properly, 
both of these qualities must be maintained. 

b. The oil's ability to transfer the heat, or its "thermal 
efficiency," largely depends on its ability to flow in and 
around the windings. When exposed to oxygen or 
water, transformer oils will form sludge and acidic 
compounds. The sludge will raise the oil's viscosity, 
and form deposits on the windings. Sludge deposits 
restrict the flow of oil around the winding and cause 
the transformer to overheat. Overheating increases the 
rate of sludge formation (the rate doubles for every 10 
°C rise) and the whole process becomes a "vicious 
cycle." Although the formation of sludge can usually be 
detected by a visual inspection, standardized American 
Society for Testing and Materials (ASTM) tests such as 
color, neutralization number, interfacial tension, and 
power factor can provide indications of sludge compo- 
nents before visible sludging actually occurs. 

c. The oil's dielectric strength will be lowered any 
time there are contaminants. If leaks are present, water 
will enter the transformer and condense around the rel- 
atively cooler tank walls and on top of the oil as the 
transformer goes through the temperature and pres- 
sure changes caused by the varying load. Once the 
water condenses and enters the oil, most of it will sink 
to the bottom of the tank, while a small portion of it 
will remain suspended in the oil, where it is subjected 
to hydrolysis. Acids and other compounds are formed 
as a by-product of sludge formation and by the hydrol- 
ysis of water due to the temperature changes. Water, 
even in concentrations as low as 25 ppm (parts per mil- 
lion) can severely reduce the dielectric strength of the 



oil. Two important tests for determining the insulating 
strength of the oil are dielectric breakdown and mois- 
ture content. 

d. The two most detrimental factors for insulating 
fluids are heat and contamination. The best way to pre- 
vent insulating fluid deterioration is to control over- 
loading (and the resulting temperature increase), and 
to prevent tank leaks. Careful inspection and docu- 
mentation of the temperature and pressures level of the 
tank can detect these problems before they cause dam- 
age to the fluid. However, a regular sampling and test- 
ing routine is an effective tool for detecting the onset of 
problems before any damage is incurred. 

5-2. Oil testing 

ASTM has developed the standards for oil testing. The 
following tests are recommended for a complete analy- 
sis of a transformer's oil: 

a. Dielectric breakdown (ASTM D-877 & D-1816). 
The dielectric breakdown is an indication of the oil's 
ability to withstand electrical stress. The most com- 
monly performed test is ASTM D-877, and because of 
this, it is more readily used as a benchmark value when 
comparing different results. The oil sample is placed in 
a test cup and an AC voltage is impressed on it. The 
electrodes are two discs, exactly 1 in. in diameter and 
placed 0.10 in. apart. The voltage is raised at a constant 
rate, until an arc jumps through the oil between Ihe two 
electrodes. The voltage at which the arc occurs is con- 
sidered the dielectric strength of the oil. For systems 
over 230 kV, this test is performed using spherical elec- 
trodes spaced 0.04 or 0.08 in. apart (ASTM D-1816). 
Portable equipment is available for performing both 
levels of this test in the field. 

b. Neutralization number (ASTM D-974). Acids are 
formed as by-products of oxidation or sludging, and are 
usually present any time an oil is contaminated. The 
concentration of acid in an oil can be determined by 
the amount of potassium hydroxide (KOH) needed to 
neutralize the acid in 1 g of oil. Although it is not a mea- 
sure of the oil's electrical strength, it is an excellent 
indicator of the pressure of contaminants. It is espe- 
cially useful when its value is monitored over a number 
of sampling periods and trending data is developed. 

c. Interfacial tension (ASTM D-971 & D-2285). The 
interfacial tension of an oil is the force in dynes per 
centimeter required to rupture the oil film existing at 
an oil-water interface, when certain contaminants, 



5-1 



TM 5-686 

such as soaps, paints, varnishes, and oxidation prod- 
ucts are present in the oil, the film strength of the oil is 
weakened, thus requiring less force to rupture. For in- 
service oils, a decreasing value indicates the accumu- 
lation of contaminants, oxidation products, or both. 
ASTM D-971 uses a platinum ring to physically break 
the interface and measure the force required. ASTM D- 
2285 measures the volume of a drop of water that can 
be supported by the oil without breaking the interface. 

d. Power factor (ASTM D-924). The power factor is 
an indication of the amount of energy that is lost as 
heat to the oil. When pure oil acts as a dielectric, very 
little energy is lost to the capacitance charging. 
Contaminants will increase the energy absorbed by the 
oil and wasted as heat. The power factor is a function 
of the phasor angle (the angular displacement) 
between an AC potential applied to the oil and the 
resulting current. The test is performed by passing a 
current through a test cell of known gap, and using a 
calibrated capacitance or resistance bridge to separate 
and compare the reactive and resistance portions of 
the current passing through the oil. 

e. Color (ASTM D-1500). The color of a new oil is 
generally accepted as an index of refinement. For in- 
service oils, a darkening of the oil (higher color num- 
ber), observed over a number of test intervals, is an 
indication of contamination or deterioration. The color 
of an oil is obtained by comparison to numbered stan- 
dards. Although there are charts available, the most 
accurate way to determine the oil's color is by the use 
of a color wheel and a comparator. An oil sample is 
placed in the comparator, and the color wheel is rotat- 
ed until a match is obtained. This test is most effective 
when results are compiled over a series of test inter- 
vals, and trending data is developed. 

/ Moisture content (ASTM D-1533). Moisture con- 
tent is very important in determining the serviceability 
of an oil; the presence of moisture (as little as 25 parts 
per million) will usually result in a lower dielectric 
strength value. Water content is especially important in 
transformers with fluctuating loads. As the tempera- 
ture increases and decreases with the changing load, 
the transformer's oil can hold varying amounts of water 
in solution. Large amounts of water can be held in solu- 
tion at higher temperatures, and in this state (dis- 
solved) the water has a dramatic effect on the oil's per- 
formance. Water contamination should be avoided. 

(1) Water content is expressed in parts per million, 
and although water will settle to the bottom of the tank 
and be visible in the sample, the presence of free water 
is not an indication of high water content, and it is usu- 
ally harmless in this state. The dissolved water content 
is the dangerous factor; it is usually measured by phys- 
ical or chemical means. A Karl Fischer titrating appa- 
ratus is one of the more common methods of measur- 
ing the dissolved water content. 



(2) There are other tests available, such as 
Flashpoint, Viscosity, and Specific Gravity. They are of 
limited value for interpretation of the oil's quality, but 
can be used for further investigation if unsatisfactory 
results are obtained for the tests listed above. 

(3) Table 5-1 lists the acceptable values for the 
laboratory test results for various insulating fluids. 

5-3. Dissolved gas in oil analysis 

The primary mechanisms for the breakdown of insulat- 
ing fluids are heat and contamination. An unacceptable 
insulation resistance value will tell you only that the 
insulation's resistance is not what is should be; it is 
hard to draw any conclusions as to why the insulation 
is deteriorating. The standard ASTM tests for insulating 
fluids will provide information about the actual quality 
of the oil, but the cause of the oil's deterioration must 
be determined by further investigation. Detection of 
certain gases in an oil-filled transformer is frequently 
the first indication of a malfunction. Dissolved gas in 
oil analysis is an effective diagnostic tool for determin- 
ing the problem in the transformer's operation. 

a. When insulating materials deteriorate, when 
sludge and acid is produced, or when arcing or over- 
heating occurs, various gases are formed. Some of 
these gases migrate to the air space at the top of the 
tank, but a significant amount is trapped, or 
"entrained," in the oil. By boiling off these gases and 
analyzing their relative concentrations with a gas chro- 
matograph, certain conclusions can be drawn about 
the condition of the transformer. 

b. Gases are formed in the oil when the insulation 
system is exposed to thermal, electrical, and mechani- 
cal stresses. These stresses lead to the following gas- 
producing events: 

(1) Overheating. Even though the insulation will 
not char or ignite, temperatures as low as 140 °C will 
begin to decompose the cellulose and produce carbon 
dioxide and carbon monoxide. When hot spot tempera- 
tures (which can be as high as 400 °C) occur, portions 
of the cellulose are actually destroyed (by pyrolysis), 
and much larger amounts of carbon monoxide are 
formed. 

(2) Corona and sparking. With voltages greater 
than 10 kV, sharp edges or bends in the conductors will 
cause high stress areas, and allow for localized low 
energy discharges. Corona typically produces large 
amounts of free hydrogen, and is often difficult to dif- 
ferentiate from water contamination and the resulting 
rusting and oxidation. When the energy levels are high 
enough to create a minor spark, quantities of methane, 
ethane and ethylene will be produced. Sparks are usu- 
ally defined as discharges with a duration of under one 
microsecond, 

(3) Arcing. Arcing is a prolonged high energy dis- 
charge, and produces a bright flame. It also produces a 
characteristic gas (acetylene), which makes it the easi- 



5-2 



TM 5-686 



Table 5-1. Insulating fluids: suggested test values 



Laboratory Test Values 


■ i High Molecular 

Weight 
Test ! Oil Hydrocarbon 


Silicone 


Tetrachloroethylene 


Dielectric 30 kV Minimum 30 kV Minimum 

Breakdown ASTM i 

D-877 


30 kV 
Minimum 


30 kV Minimum 


Neutraliza- tion [.04 MG- ,.03 MG- 
NumberASTM D-974 : KOH/GMMaximum KOH/GMMaximum 

i : 
i 


.01 MG- 

KOH/GMMaxim 
um 


.25 MG- KOH/GMMaximum 


InterfacialTensi 35 33 

onASTM D-971 1 Dynes /cmMinim Dynes/cmMinimum 

orD-2285 | urn 








ColorASTM D-1500 1 . OMaximum ! N/AMaximum 

i : 
i 


.05 (D- 
2129) 





VisualConditionA : Clear, N/A 
STM D-1524 :BrightPale 
i Straw 


Crystal 
Clear (D- 
2129) 


Clear, SlightPink 
Iridescent 


Power FactorASTM ! . l%Maximum . l%Maximum 
D-924®25 Deg. C i 


. l%Maximum 


2%Maximum 


Water 35 35 PPMMaximum 
Con ten t A STM D- PPM*Maximum 
153315 kV 
andbelow j 


80 
PPMMaximum 


25 PPMMaximum 


Above 15 kV - |25 

below 115 kV PPM'Maximum 








115 kV-230 kV 


20 PPMMaximum 


^^___ 


. 


Above 230 kV 


15 PPMMaximum 








*0r in accordance with manufacturer's requirements. Some manufacturers recommend 15 
PPM maximum for all transformers. 



est fault to identify. Acetylene will occur in a trans- 
former's oil only if there is an arc. 

(a) Other conditions that will cause gases to 
form in the transformer's oil include tank leaks, oil con- 
tamination, sludging and residual contaminants from 
the manufacturing and shipping processes. In most 
cases, the determinations that can be made are "edu- 
cated guesses," but they do at least provide a direction 
and starting point for further investigation. Also, many 
of the gases can be detected long before the trans- 
former's condition deteriorates to the point of a fault or 
unacceptable test results. 

(b) In general, combinations of elements that 
occur naturally in pairs, such as hydrogen (H 2 ), oxygen 
(0 2 ), and nitrogen (N 2 ) reflect the physical condition 
of the transformer. Higher levels of these gases can 
indicate the presence of water, rust, leaky bushings, or 
poor seals. 

(c) Carbon oxides such as CO and C0 2 reflect 
the demand on the transformer. High levels of each can 
show whether the transformer is experiencing minor 



overload conditions, or if it, is actually overheating. 

(d) The concentrations of hydrocarbon gases, 
such as Acetylene, ethylene, methane and ethane indi- 
cate the integrity of the transformer's internal func- 
tions. Acetylene will be produced only by a high energy 
arc, and the relative concentrations of the others can 
indicate cellulose breakdown, corona discharge or 
other faults. 

(e) Tables 5-2 and 5-3 show the various gases 
that can be detected, their limits, and the interpreta- 
tions that can be made from their various concentra- 
tions. 

(f) Dissolved gas in oil analysis is a relatively 
new science, and new methods of interpretation are 
constantly being devised. The Rogers Binary ratio, The 
Dornenberg Ratios, and the Key Gas/Total Combustible 
Gas methods are just a few. This type of analysis; is still 
not an exact science (it began in the 1960s), and as its 
use becomes more widespread and the statistical base 
of results grows, the determinations will become more 
refined. 



5-3 



TM 5-686 



Table 5-2. Dissolved gas in oil analysis. 



Gases 


Suggested Gas Limits in PPM 
for In -Use Transformers 


Names and Symbols for 
Gases 


H 2 100 


Hydrogen 


H 2 


o 2 


50,000 


Oxygen 


°2 


CH 4 


120 Nitrogen 


N 2 


C 2 H 2 


35 Carbon j CO 
; Monoxide 


C 2 H 4 30 [Carbon Dioxide 


co 2 


C 2H 6 j 65 


Methane 


CH 4 


CO | 350 


Ethane 


C 2 H 6 


co 2 


1000 


Ethylene 


C 2 H 4 






Acetylene 


C 2 «2 




Propane 


C 3 H 8 






Propylene 


C 3 H 6 




J Butane 


C 4 H 10 


Below is a table showing gas combinations and their 
interpretations indicating what may be happening inside 
the operating transformers. 



5^4. Transformer oil sampling 

Samples can be drawn from energized transformers, 
although extreme caution should be observed when 
working around an energized unit. It is a good practice, 
for both energized and de-energized units, to attach an 
auxiliary ground jumper directly from the sample tap to 
the associated ground grid connection. 

a. During the first year of a testing program, inspec- 
tions and sampling should be conducted at increased 
frequencies. Baseline data must be established, and 
more frequent testing will make it easier to determine 
the rate of change of the various items. A conservative 
sampling interval would be taken immediately after 
energization, and every 6 months for the first year of a 
newly initiated program. Specialized applications such 
as tap changers and regulators should be sampled more 
frequently. Except for color and dielectric strength, 
which can be tested easily in the field, it is recom- 
mended that oil analysis be performed by a qualified 
laboratory. 

b. Glass bottles are excellent sampling containers 
because glass is inert and they can be readily inspected 
for cleanliness before sampling. Impurities that are 
drawn will be visible through the glass. The bottles can 
be stoppered or have screw caps, but in no instance 
should rubber stoppers or liners be used; cork or alu- 
minum inserts are recommended. Clean, new rectangu- 



lar-shaped, 1 -quart cans with screw caps and foil 
inserts are also good, especially when gas-in-oil analy- 
sis is to be performed. Glass bottles and cans are well 
suited if the sample must be shipped or stored. For 
standard oil testing, a small head space should be left 
at the top of the container to allow for this expansion 
and contraction. For dissolved gas in oil, the can 
should be filled all the way to the top to eliminate the 
infusion of atmospheric gases into the sample. 

c. Because the usefulness of oil testing depends on 
the development of trending data, it is important for oil 
samples to be drawn under similar conditions. The 
temperature, humidity, and loading of the transformer 
should be documented for each sample, and any varia- 
tions should be considered when attempting to develop 
trending data. Samples should never be drawn in rain 
or when the relative humidity exceeds 70 percent. 
Different sampling techniques can alter the results, and 
steps should be taken to ensure that all samples are 
drawn properly. 

d. When possible, oil samples should always be 
drawn from the sampling valve at the bottom of the 
tank. Because water is heavier than oil, it will sink to 
the bottom and collect around the sampling valve. To 
get a representative sample, at least a quart should be 
drawn off before the actual sample is taken. If a num- 
ber of samples are taken, they should be numbered by 
the order in which they were drawn. 



5-4 



TM 5-686 



Table 5-3. Troubleshooting transformers with detected gases. 



Troubleshooting Chart 



Detected Gases 



Interpretations 



a) Nitrogen plus 5% or less oxygen Normal operation, good seals 



b) Nitrogen plus 5% or more oxygen Check seals for tightness 



c) Nitrogen, carbon dioxide, or 
carbon monoxide, or all 



: Transformer overloaded or operating 
■hot causing some cellulose 

breakdown. Check operating 

conditions 



d) Nitrogen and hydrogen 



Corona, discharge, electrolysis of 
water, or rusting 



e) Nitrogen, hydrogen, carbon 
dioxide and carbon monoxide corona 
discharge involving cellulose or 
severe overloading 



f) Nitrogen, hydrogen, methane with Sparking or other minor fault 
small amounts of ethane and ethylene causing some breakdown of oil 



g) Nitrogen, hydrogen, methane with : Sparking or other minor fault 
carbon dioxide, carbon monoxide and causing breakdown of oil 
small amounts of other hydrocarbons; 
acetylene is usually not present 



h) Nitrogen with high hydrogen and 
other hydrocarbons including 
acetylene 



High energy arc causing rapid 
deterioration of oil 



I) Nitrogen with high hydrogen, 
methane, high ethylene and some 
acetylene 

j) same as (I) except carbon 
dioxide and carbon monoxide present. 



High temperature arcing of oil but 
in a confined area; poor connections 
or turn -to -turn shorts are examples 
j same as (I) except arcing in 
combination with cellulose 



e. The sample jars should be clean and dry, and both 
the jars and the oil should be warmer than the sur- 
rounding air. If the transformer is to be de-energized for 
service, the samples should be taken as soon after de- 
energization as possible, to obtain the warmest oil dur- 
ing the sampling. The sample jars should also be thor- 
oughly cleaned and dried in an oven; they should be 
kept warm and unopened until immediately before the 
sample is to be drawn. 

5-5. Synthetics and other insulating 
fluids 

Although there are a number of synthetic compounds 
available, such as silicone, trichloroethane, and various 
aromatic and parafinic hydrocarbons, the most com- 
mon transformer insulating fluids currently in use are 
mineral oil and PCBs. The use of PCB has been severe- 
ly restricted recently, and special attention should be 
given to its maintenance and disposal. 

a. PCB (polychlorinated biphenyl). PCBs have been 
used extensively in industry for nearly 60 years. PCBs 
were found to be especially suited for transformer 



applications because they provided excellent insulat- 
ing properties and almost no fire hazards. In the 1960s, 
it was discovered that PCB, and especially the products 
of its oxidation were harmful to the environment and to 
the health of personnel. The USEPA began regulating 
PCBs in the 1980s, and although the regulations are 
constantly being changed and updated, prudent and 
conservative policies should always be applied when 
dealing with PCBs. PCB should not be allowed to come 
in contact with the skin, and breathing the vapors or 
the gases produced by an arc should be avoided. Safety 
goggles and other protective equipment should be 
worn when handling PCBs. Even though PCBs .are no 
longer being produced, there are still thousands of PCB 
transformers in the United States alone. Transformers 
that contain PCBs should be marked with yellow, 
USEPA-approved stickers. The concentration of PCB 
should be noted on the sticker, and all personnel work- 
ing on or around the transformer should be aware of 
the dangers involved. A PCB transformer should be 
diked to contain any spills, and all leaks should be rec- 
tified and reported as soon as possible. If the trans- 



5-5 



TM 5-686 

former requires addition fluid, only approved insulating 
fluids, such as RTemp should be mixed with the PCB. If 
the handling and disposal of PCB materials is required, 
only qualified personnel should be involved, and strict 
documentation of all actions should be maintained. It is 
recommended that only qualified professionals, trained 
in spill prevention and containment techniques, be per- 
mitted to work on PCB transformers. 

b. Silicone. Silicone fluid is also used widely for 
many applications. It is nearly as fire resistant as PCB, 
and provides many of the same performance benefits. 
It is also more tolerant of heat degradation and conta- 
mination than most other fluids, and will not sludge 
when exposed to oxidation agents. 

(1) The specific gravity of silicone, however, 
changes with temperature. Silicone's density varies 
between 0.9 and 1.1 times that of water, which causes 



water to migrate from the top to the bottom of the tank 
as the temperature changes. This is especially detri- 
mental in transformers that undergo large or frequent 
loading and temperature changes. 

(2) Silicone also changes in volume more during 
the temperature changes and this places greater stress 
on the various gaskets and covers on the tank. Added 
pressure compensating and relief devices are usually 
found on silicone units. 

(3) Many other types of insulating fluids are cur- 
rently in use for specialized applications. Although they 
may have complex chemical make-ups, most of the 
maintenance strategies listed in this section will apply; 
contamination and overheating are their worst ene- 
mies. The manufacturer's instruction booklets should 
be referred to when working with these fluids. 



5-6 



TM 5-686 



CHAPTER 6 
INITIAL ACCEPTANCE INSPECTION/TESTING 



6-1. Acceptance 

While testing and inspection programs should start 
with the installation of the transformer and continue 
throughout its life, the initial acceptance inspection, 
testing and start-up procedures are probably the most 
critical. The initial inspections, both internal and exter- 
nal, should reveal any missing parts or items that were 
damaged in transit; they should also verify that the 
transformer is constructed exactly as specified. The 
acceptance tests should reveal any manufacturing 
defects, indicate any internal deficiencies, and estab- 
lish baseline data for future testing. 

a. The start-up procedures should ensure that the 
transformer is properly connected, and that no latent 
deficiencies exist before the transformer is energized. 
Ensuring that the transformer starts off on "the right 
foot" is the best way to guarantee dependable opera- 
tion throughout its service life. 

b. Various manufacturers recommend a wide range 
of acceptance and start-up procedures. Although basic 
guidelines and instructions are presented here, in no 
case should be manufacturer's instructions and recom- 
mendations be ignored. The intent of this manual is to 
present the practical reasoning behind the procedures 
recommended by the manufacturer. In some cases, the 
following procedures will exceed the manufacturer's 
recommendations, and in others, the manufacturer will 
call for more involved and comprehensive procedures. 
When in doubt, consult the manufacturer's guidelines. 

6-2. Pre-arrival preparations 

Before the transformer arrives, the manufacturer 
should be contacted to ensure that all arrangements 
can be completed smoothly. If possible, the start-up lit- 
erature or owner's manuals should be provided by the 
manufacturer before the transformer arrives, so that 
preparations can be made. 

a. Dimensions and lifting weights should be available 
to ensure that the transformer can be easily moved and 
positioned. If at the possible, the transformer should be 
moved to its final installation point immediately on 
arrival. If the transformer must be stored before ener 
gization, steps should be taken to see that the area 
where it is stored is fairly clean and not exposed to any 
severe conditions. Regular inspections and complete 
documentation should be maintained for the trans- 
former while it is stored. Manufacturers will prescribe 
completely different start-up procedures, depending on 



how long and in what type of environment a trans- 
former has been stored. 

b. The equipment necessary for start-up should be 
assembled after the site preparations have been com- 
pleted, and all receiving and unloading arrangements 
have been made. The following equipment may be nec- 
essary depending on the type of transformer, how it is 
shipped, and its condition on arrival. 

(1) Lifting/moving equipment. If the transformer 
must be moved, it should be lifted or jacked only at the 
prescribed points. Most transformer tanks are 
equipped with lifting eyes, but if they are shipped with 
their bushings or radiators in place, they will require 
special slings and spreaders to prevent the equipment 
from being damaged. Also, it is important to remember 
to never use the radiators, bushings, or any other aux- 
iliary equipment to lift or move the transformer or to 
support a person's weight. Having the proper equip- 
ment on site will expedite the unloading and placement 
of the transformer. 

(2) Test equipment Depending on the start-up 
procedure, any of the following items may be required: 
A megohmmeter ("megger") insulation resistance test 
set, transformer turns ratio test set, power factor tet 
set, liquid dielectric test set, dew point analyzer, oxy- 
gen content analyzer, and various thermometers and 
pressure gauges. Sample jars should also be available, 
and samples should be taken both before and alter oil- 
Filling operations. 

(3) Vacuum and filtering equipment. Even if the 
oil being used has good dielectric strength, a good filter 
will remove any entrained water or contaminants intro- 
duced during the filling process. Most transformer oils 
require a 5-micron filter media. The capacity of the vac- 
uum pump will depend on the physical size and voltage 
rating of the transformer. Larger tanks may require a 
pump capable of 200 cfm, and transformers with volt- 
ages above 69 kV may require a sustained pressure/vac- 
uum level of 2-50 Torr (one torr is a unit of very low 
pressure, equal to 1/760 of an atmosphere). The blank 
off pressure (the minimum pressure the pump can 
attain at the inlet) and CFM ratings are usually provid- 
ed on the pump's nameplate. An assortment of pipe and 
fittings should also be available to make the necessary 
connections. An assortment of caps, plugs, and valves 
should also be available for blanking off any equipment 
that could be damaged by the vacuum. 

(4) Gas cylinders. Nitrogen will be needed for 



6-1 



TM 5-686 

applying the gas blanket and breaking the vacuum. Dry 
air will be needed if the tank must be entered for 
inspection or equipment installation. As a safety pre- 
caution, bottled pure oxygen must be available anytime 
anyone enters the tank. 

(5) Safety equipment. At least two 20-pound C0 2 
extinguishers must be available for internal or external 
use. One 20-pound dry powder extinguisher should be 
available for use on the exterior of the transformer. All 
personnel should be thoroughly trained and capable of 
implementing fire-fighting, spill containment, first aid, 
and other emergency procedures. 

(6) Miscellaneous equipment. A camera should be 
available to document any discrepancies that are found 
during the receiving or internal inspections. Large tents 
or enclosures will be required if the transformer must 
be opened or filled in inclement weather. Ladders or 
scaffolding will be necessary depending on the size of 
the transformer. Explosion-proof lamps enclosed in a 
fine stainless steel mesh will be required to provide light 
inside the tank. Drop cloths or plastic sheets should be 
used to prevent material from dropping into the tank or 
winding assembly. All tools or materials that enter the 
tank must be accounted for; it is a good idea to attach 
strings to any small objects that enter the tank. 

6-3. Receiving and inspection 

When the transformer arrives, all paperwork should be 
checked to ensure that the transformer is constructed 
and equipped exactly as specified. Parts lists should be 
checked and all parts should be counted to ensure that 
nothing has been omitted. Any auxiliary equipment or 
shipping crates should be inspected for evidence of 
damage. Careful attention should also be paid to mois- 
ture barriers or waterproof wrappings; if they are torn 
or damaged, the equipment inside may need to be dried 
out. 

a. The external inspection should be completed 
before the transformer is unloaded, and, if major prob- 
lems are discovered, an internal inspection should be 
conducted. External inspection should verify the fol- 
lowing: 

(1) Tie rods and chains are undamaged and tight. 

(2) Blocking and bracing are tight. 

(3) There is no evidence of load shifting in transit. 

(4) If there is an impact recorder, whether it indi- 
cates any severe shocks. 

(5) Whether there are indications of external dam- 
age, such as broken glass or loose material. 

(6) Whether there are any obvious dents or 
scratches in the tank wall or auxiliary compartments. 

(7) Whether there is evidence of oil leakage. 

(8) Whether there is positive pressure or vacuum 
in the tank. 

(9) Whether porcelain items have been chipped or 
bent at their mounting flanges. 

6. If any of the above items are noted, it should be 



clearly marked on the delivery receipts, and the manu- 
facturer should be contacted. If an internal inspection 
is required, the manufacturer's and or carrier's repre- 
sentatives may need to be present. 

6-4. Moving and storage 

If at all possible, the internal inspection should be con- 
ducted before the transformer is unloaded. If the trans- 
former must be unloaded for an internal inspection, it 
should be moved directly to the point of installation. 

a. When unloading the transformer or placing it in 
position, be sure to use the designated lifting eyes or 
jacking points, the transformer should be handled in 
the normal upright position, and in no case should it be 
tilted more than 15 degrees. Spreaders should be used 
to hold the lifting cables apart, particularly if they are 
short and may bear against external assemblies or 
bushings. Do not attempt to lift or drag the transformer 
by placing a loop or sling around it, and do not use 
radiators, bushings, or other auxiliary equipment for 
climbing or to lift the transformer. Transformers ar 
extremely dense and heavy, much heavier than circuit 
breakers or other switchgear items. A conservative 
safety factor should always be applied when a trans- 
former must be lifted. 

b. An internal inspection is called for if there is evi- 
dence of damage, or if the transformer is to be stored. 
When the unit is to be stored for more than 3 months, 
it should be protected from the weather. All scratches 
or paint defects should be touched up before storage. If 
the transformer is filled with oil, it should be tightly 
sealed so that no moisture or air can enter the case. If 
the transformer is shipped filled with inert gas, period- 
ic inspection should determine that a positive pressure 
of about 2 psi is maintained at all times. Water-cooled 
transformers should have the water-cooling coils filled 
with alcohol or other similar antifreeze to eliminate any 
danger of freezing or contamination. 

c. Regular inspection and documentation procedures 
should be conducted during transformer storage. All 
inspection and service procedures should be thorough- 
ly documented, and any discrepancies or adverse con- 
ditions should be noted. Pumps and fans should be 
operated for 30 minutes, once a month. At the end of 
the storage period, oil samples should be drawn and 
analyzed for dielectric strength, power factor, and 
water content. Insulation resistance and power factor 
tests should be conducted on the transformer and com- 
pared to the original factory data. 

d. Larger transformers are often shipped without oil. 
They are vacuum filled with hot oil at the factory to 
impregnate the winding insulation with oil. The oil is 
then removed for shipping. This oil impregnation is vital 
to the winding's insulation strength, and will be lost if 
the transformer is stored for too long without oil. Most 
manufacturers recommend a maximum storage time of 
3 months without oil. If this storage time is exceeded, 



6-2 



TM 5-686 



hot oil vacuum degasification must be performed, and 
the manufacturer's guidelines should be followed. 

6-5. Internal inspection 

If an internal inspection is called for, or if the trans- 
former must be opened to install bushings and other 
auxiliary equipment, two factors should be of primary 
importance: (1) to make every attempt to minimize the 
time the transformer is opened; (2) to take whatever 
measures necessary to ensure that no moisture, foreign 
material, or other contaminants enter the tank. 

a. The time element can be minimized by assembling 
all necessary tools and materials before the tank is 
opened. Personnel conducting the inspection/assembly 
should review all procedures and be prepared to com- 
plete their work as quickly as possible. They should 
also be prepared to implement any fire fighting or 
emergency procedures. If the tank must be entered, all 
personal should empty their pockets and ensure that 
no loose debris is in their pant cuffs or on their shoes. 
Approved shoe coverings should be worn by anyone 
who will be on top or inside the transformer. It is also 
good idea to use drop cloths under all internal work 
where practical, and to inventory and tie-off all tools 
being used. One person should be responsible for polic- 
ing the people and materials into and out of the trans- 
former, and for making certain nothing is left in the 
transformer. 

b. Transformers are capable of stepping harmless 
voltages up to dangerous levels. This applies to both 
low level test potentials, and to static charges built up 
between equipment, windings, tank walls, and person- 
nel. This danger is further complicated by the flamma- 
bility of transformer oil. All windings, bushings, pumps, 
pipes, filter equipment and external connections 
should be solidly grounded during the inspection, test- 
ing, and assembly procedures. Grounds should also be 
applied to any component of the transformer immedi- 
ately after a test potential is applied to the component. 

c. Transformer tanks are usually pressurized with dry 
nitrogen for shipping. The pressure must be broken 
slowly and dry air must be introduced; an oxygen con- 
tent of 20 to 25 percent should be confirmed before 
entering the tank. It is important to remember that tank 
pressures as low as 1 psi will blow covers and fittings 
off as they are being removed. Ensure that all tank and 
compartment pressures have been equalized before 
opening the tank. 

d. After the tank pressure has been equalized, and 
the proper oxygen content has been verified, the tem- 
perature of the core and coils should be measured. The 
tank should not be opened unless the temperature of 
the internal portion of the transformer is at least 2°F 
above the dew point of the outside air. The dew point is 
a measure of the ability of the surrounding air to allow 
moisture to condense on the transformer's surfaces. 

e. Dew point measurements of transformers shipped 



without oil can be made with a number of different 
instruments. The Alnor Model 7300 is commonly used 
for transformer start up. Dew point testers operate on 
the principle that moisture in a gas will precipitate or 
"fog" in a definite relationship to the temperature and 
the degree of moisture in the air. By ascertaining that 
the outside air is low enough in moisture content, and 
that the temperature of the transformer's components 
is high enough, the possibility of introducing unwanted 
moisture into the transformer can be nearly eliminated. 

/ Tents and heated temporary enclosures can be 
used to provide a controlled environment if the work 
must be completed in inclement wether. Even if the the 
external conditions are satisfactory, it is a good idea to 
blow a pressurized stream of bottled dry air through 
the tank while it is open. Creating a slight positive pres- 
sure will prevent outside air from entering the tank. 

g. If the transformer is shipped filled with oil, the 
internal inspection can be conducted by lowering the 
oil level to just above the windings. This can usually be 
accomplished by installing the radiators and allowing 
the oil to flow into them. Be certain radiators have been 
cleaned and pressure checked before installing, and 
gaskets and valves are installed correctly. An explosion 
proof spotlight with an oil resistant cord can be low- 
ered into the tank to conduct the inspection. 

h. If the oil must be lowered below the windings, and 
the windings are exposed for more than 24 hours, all of 
the oil should be removed and the transformer refilled 
using hot vacuum degassing techniques. Because the 
equipment required for hot vacuum degassing is rather 
involved and costly, it is recommended that the manu- 
facturer or qualified professional be present for the 
operation. 

i. The objective of the internal inspection is to locate 
any damage that may have occurred during shipment. 
Examine the top of the core and coil assembly, all hor- 
izontal surfaces, and especially the underside of the 
cover for signs of moisture. All leads, bolted mechani- 
cal and electrical joints, current transformers and insu- 
lation structures should be thoroughly inspected. The 
tap changer should be exercised, and all connections 
verified. Terminal boards should be checked to see that 
connections are as specified. 

j. Although most testing should be performed only 
while the coils are submerged in oil, if the inspection is 
being conducted because of problems noted during the 
external or internal inspections, the following tests 
should be conducted: 

(1) Power factor tests for all winding to ground 
and windings to winding values. 

(2) Turns ratio tests for all windings and tap posi- 
tions. 

(3) Ratio and polarity tests for all current trans- 
formers. 

(4) Winding resistance checks for all primary and 
secondary windings. 



6-3 



TM 5-686 



(5) Discount the grounding connections between 
the core assembly and the tank, and perform insulation 
resistance tests with a megger. 

k. These test values should be compared to the facto- 
ry supplied test data. All temperature and humidity 
readings should be recorded to facilitate this com- 
parison. 



6-6. Testing for leaks 



If the test results indicate a moisture or contamination 
problem with the transformer, if the gauges register 
zero pressure on arrival, or if moisture is discovered 
during the internal inspection, the transformer should 
be tested for leaks before final vacuum filling begins. 

a. Most transformers are pressurized to approxi- 
mately 3 psi for shipping. It is important to remember 
that this pressure will fluctuate according to tempera- 
ture; a zero pressure gauge reading is not a sure sign of 
a leak. If the pressure registers zero in the sunlight and 
at nighttime (over a range of more than 10 °F), then a 
leak can be suspected. 

b. Leaks can be detected by applying a positive pres- 
sure to the tank. All bushings, radiators, gauges and 
auxiliary equipment should be installed before a leak 
check is conducted. Some items may need to be 
blanked off for the pressure check, and the pressure 
should be raised slowly so as not to damage the sudden 
pressure relay or any other sensing devices. Verify the 
maximum pressure capabilities of the tank (usually 
found on the nameplate or in the shipping specifica- 
tions) and use bottled nitrogen to apply the pressure, 
being careful to always stay at least 1 psi below the 
maximum allowable. If the tank is empty, a soap/glyc- 
erin solution should be applied to all seams, gaskets 
and fittings. Bubbling and sputtering noises will indi- 
cate the location of the leak. If the tank is filled with oil, 
the soap solution should be applied above the oil level, 
and chalk dust applied below the oil level. Chalk dust 
will darken noticeably where any oil is seeping out. 

c. Small leaks at seams and welds can be carefully 
hammered shut with a ball peen hammer, although 
larger ones may require welding or epoxy patching. 
Leaking gaskets should be replaced, and fittings can 
usually be removed and resealed using glyptal, Teflon 
tape, or other sealing compounds. The manufacturer 
should be contacted to ensure the use of proper com- 
pounds. Vacuum filling operations can begin once the 
leads have been replaced and the interior of the trans- 
former has been determined to be dry. 

d. The core and coils may need tobe dried if a major 
leak was found, if the transformer has been opened for 
an extended period, or if unsatisfactory test results 
were obtained for any of the preliminary testing. 
Drying the transformer is an involved and potentially 
damaging process; effective drying of the core insula- 
tion requires temperatures in excess of 90 °C. 
Manufacturers recommend a variety of procedures for 



drying and determining when the transformer is suffi- 
ciently dry. The manufacturer should be contacted if 
excessive moisture is suspected. 

6-7. Vacuum filling 

New oil can contain enough contaminants to cause a 
fault when the transformer is first energized. The pres- 
ence of small quantities of contaninants will begin on 
ongoing degradation of the oil's quality. The quality of 
transformer oil depends on its purity; many factors in 
shipping and storage cannot be controlled once the oil 
leaves the refinery. The most effective way to ensure 
that no impurities are introduced into the oil is to filter 
the oil and fill the tank under vacuum. Filtering will 
remove any entrained water or other contaminants, 
and as the stream of oil hits the vacuum, most small 
bubbles will be drawn out of the liquid and "explode" 
s they equalize with the vacuum condition in the tank. 

a. Oil should be tested before it is introduced into the 
transformer. This should include field testing for 
dielectric, and drawing samples for laboratory analysis. 
If problems are encountered later, the results of this 
testing can provide valuable information for determin- 
ing why and how problems are occurring. Testing also 
provides a good indication of how effective the filtering 
and vacuum operations were. 

b. Before vacuum filling operations can begin, it is 
important to determine the maximum vacuum level the 
tank can withstand, and to ensure that any auxiliary 
devices can also withstand the same vacuum level. 
Items such as conservator tanks and compartment 
dividers will not be capable of withstanding the full 
vacuum applied to the tank. Additional pipe and fittings 
must be used to valve off or equalize the pressure that 
will be created by the vacuum. Other items, such as 
dehydrating breathers and pressure vacuum bleeders 
will have to be removed or valved off. It is important to 
consult the manufacturer's literature on these devices 
before applying the vacuum. 

c. It is also important to remember that the tank will 
deflect according to the varying pressures. All rigid 
connections to the tank, except at the base, should be 
disconnected before applying the vacuum. This is espe- 
cially true for bushings, lightning arresters, and other 
porcelain equipment. 

d. Once the necessary preparations have been made, 
the vacuum/filtering apparatus should be connected as 
shown in figure 6-1. 

e. When hooking up the equipment and applying the 
vacuum, the following conditions should be observed: 

(1) All pipe connections from the pump to the 
transformer tank should be as short and as large in 
diameter as possible. 

(2) All transformer leads, pumps, and bushings 
should be grounded to prevent the build-up of static 
charge. 

(3) The vacuum gauge should be installed on the 
top of the tank itself, and not on any of the vacuum 



6-4 



TM 5-686 



VACUUM GAUGE 



INTERRUPTER - 



SELECTOR ■ 



OIL FILTER ■ 




d 



-CONSERVATOR 



■BRACING 
BANDS 



-COOLING 



REGULATOR 




lines. Use an aneroid or thermocouple gauge; the use of 
mercury gauges is recommended only if provisions are 
made to contain the mercury in the event that the 
gauge is broken. 

(4) The oil inlet should be positioned so that oil 
will not enter the vacuum pump. A liquid trap should be 
installed in the vacuum lines to protect the pump from 
the oil. 

(5) The flow of oil should be controlled so that oil 
cannot enter the sudden pressure relay or other auxil- 
iary equipment. 

(6) All valves to radiators and heat exchangers 
should be open. 

/ Once the equipment has been assembled, make 
certain that enough oil is on site to complete the job 
without stopping. During the vacuum and liquid-filling 
operations, the temperature of the core and coils must 
be above °C. The oil temperature should be at least 
2 °C higher, but in no case less than 10 °C. The length 
of time and the magnitude of the vacuum will depend 
on a number of factors, including the size of the tank, 
the length of time the tank was opened, and the voltage 
rating of the transformer. The individual manufactur- 
er's recommendations should be consulted, and the fol- 
lowing times should be considered as minimums: 

(1) Apply the vacuum for at least 3 hours before 
oil-filling begins. 

(2) Never allow the vacuum to fall below 80 per- 
cent of the original level while pumping the oil in. 

(3) Maintain the vacuum for at least 3 hours after 
the transformer is full. 



Figure 6-1. Transformer tank with vacuum filling. 

g. While the vacuum is being applied, the trans- 



former is especially susceptible to contamination by 
outside factors. There should be no leaks in the tank, 
hoses, or any of the auxiliary equipment, and the entire 
set-up should be protected from rain or moisture. 

h. When the tank has been fdled to the proper level, 
the vacuum should be broken slowly with nitrogen and 
pressurized to 3 psi. Once the pressurized nitrogen is 
applied, the cooling pumps should be operated for at 
least 1 hour to reduce the possibility of trapped resid- 
ual gas. The transformer should then be allowed to 
stand without load for at least 12 hours before any tests 
are performed. 

i. After the 12-hour standing period, the following 
tests should be performed to establish baseline data for 
the transformer. 

(1) Transformer turns ratio. This test ensure that 
no material or tools are shorting the windings. 

(2) Insulation resistance-dielectric absorption. 
This test is used to determine whether any grounds 
have been left on the windings, and whether the insu- 
lation quality is strong enough for energization. 

(3) Winding continuity resistance test. This test 
should be compared to the factory supplied readings; a 
reading that is ore than 10 percent higher could indi- 
cate loose internal connections. 

(4) Power factor test. This test will indicate the 
quality of the combined insulating fluid and winding 
insulation. It will also provide important baseline data 
for future testing. Values in excess of 1 percent could 



6-5 



TM 5-686 

indicate dampness in the transformer. Consult the man- 
ufacturer's instructions for drying procedures. 

(5) Insulating fluid testing. This test will help to 
provide additional information if any discrepancies are 
noted in the above testing. Samples should be drawn 
for the complete series of lab tests, including dissolved 
gas, and dielectric strength field testing. The dielectric 
strength for new oil should be at least 35 kV. 

j. After the testing is completed, the transformer 
should be energized for at least 12 hours before apply- 
ing the load. Because very high currents can be devel- 
oped when the transformer is first energized, any 
upstream fuses or fused devices should be checked 
immediately after the power is applied. If a fuse should 
blow, and if the transformer is allowed to operate with- 
out one or two fuses, it could be damaged, even if no 
load is applied. 



k. After 12 hours, the load should be applied slowly, 
and the transformer should be carefully monitored ass 
the load is being applied. Even though satisfactory test 
results have been obtained, personnel should stay clear 
of the transformer during the first 24 hours of ener- 
gization, it is during this time that any entrapped air 
will come to the surface, and the possibility of a fault or 
a short should always be considered. 

L All of the acceptance test data should be recorded 
and used as baseline data for future testing. It is a good 
idea to keep copies of all test data, start-up documen- 
tation, and product information in a file cabinet with all 
of the other electrical system documents. The proper 
documentation, storage and accessibility of all product 
information, tests and procedures is one of the most 
important factors in a comprehensive and effective 
maintenance program. 



6-4 



TM 5-686 



CHAPTER 7 
TRANSFORMER TESTING 



7-1. Test data 

Electrical performance testing is one of the most 
important components of a comprehensive mainte- 
nance program. Test data, when taken under, or cor- 
rected to, standard conditions, will yield valuable data 
about the rate of deterioration of a piece of electrical 
equipment. Once this rate is determined, service fac- 
tors can be adjusted, and potential problems alleviated. 

a. Almost all electrical failures, in all sorts of electri- 
cal equipment, can be traced to a failure of the insula- 
tion. Periodic testing will indicate the condition of the 
insulation at the time of the test, but does little to show 
the actual amount of deterioration the insulation has 
undergone during its service life. Only by establishing 
baseline data and performing regular tests under con- 
trolled conditions can trending data be developed to 
yield true indications of the insulation's condition. 

b. Insulating fluids analysis is probably the most 
practical and indicative test of a transformer's condi- 
tion. It provides the opportunity to actually remove a 
portion of the transformer's insulation and subject it to 
a series of standardized tests under controlled labora- 
tory conditions, with the benefit of complex laboratory 
equipment. One of the most important links in the 
effectiveness of insulating fluids testing is the quality of 
the sample. 

c. Except for sampling and inspection, all trans- 
former tests should be performed on de-energized 
equipment. Even for sampling and inspections, the tank 
ground should be verified before coming into contact 
with any of the transformer's outer surfaces. The tests 
listed in this chapter and in chapter 10 should be per- 
formed only after the circuits are de-energized and 
checked both at the source and at the test location. See 
the safety procedures in chapter 1. 

d. One of the most important factors in conducting 
transformer tests is the condition of the unit under test. 
A thorough inspection of the unit should be performed 
before the test, and any questionable conditions should 
be noted on an inspection record. All temperature and 
pressure readings should be recorded along with the 
atmospheric conditions (temperature and humidity) at 
the time of the test. 

e. Test procedures should be as similar as possible 
from one test to another. All connections, test voltages 
and time intervals should be repeated exactly for each 
test cycle. By performing the tests in a set method, and 
correcting all test results to a standard temperature 



value (20 °C), the data for different test intervals can be 
compared to indicate the rate of deterioration of the 
transformer. 

7-2. Direct current testing 

Transformer tests can be divided into two categories, 
alternating current (AC) and direct current (DC). 
Direct current testing is widely accepted because of the 
portability of the equipment and because of the nonde- 
structive nature of the tests. Because the test potential 
can be applied without the reactive component (capac- 
itive and inductive charging and recharging), DC tests 
can be performed at higher levels without stressing the 
insulation to the same degree as an AC test. It is impor- 
tant to note that, even though a winding failure may 
result, it probably resulted from an incipient condition 
that the test was designed to detect. If the deficiency 
had gone undetected, the failure may have occurred at 
an unplanned time and resulted in additional equip- 
ment damage. 

a. When a DC potential is applied across an insula- 
tion, there are three components to the resulting cur- 
rent. An understanding of the nature of these currents 
will help with the application of the tests and the inter- 
pretation of the resulting data. 

(1) Capacitance charging current. When the insu- 
lation resistance is being measured between two con- 
ductors, the conductors act like the plates in a capaci- 
tor. These "plates" absorb a certain amount of 
electrical energy (the charging current) before the 
applied voltage is actually developed across them. This 
current results in stored energy that should be dis- 
charged after the test by shorting across the insulation. 

(2) Dielectric absorption current. As noted above, 
the two conductors between which the potential is 
being applied act like a capacitor. The winding insula- 
tion and the insulating fluid then act as dielectric mate- 
rials and absorb electrical energy as their molecules 
become polarized, or charged. The absorption current 
decreases as the materials become charged, resulting 
in an apparent increase in the insulation resistance. 
The absorption current results in stored energy that 
takes longer to dissipate than it did to build. The insu- 
lation should be shorted for a time period equal to or 
longer than the time the test was applied, preferably 
longer. 

(3) Leakage current. This is the current that actu- 
ally flows throughout the insulation or across its sur- 



7-1 



TM 5-686 



face. Its magnitude is usually very small in relation to 
the rated current of the device, and it is usually 
expressed in microamperes (one millionth of an amp). 
It indicates the insulation's actual conductivity, and 
should be constant for a steady applied voltage. 
Leakage current that increases with time for a constant 
applied voltage indicates a potential problem. 

b. The following tests are designed to provide indica- 
tions of the transformer's condition and suitability for 
service. The recommended frequency and relationship 
in a comprehensive maintenance/testing program is 
discussed in chapter 10. 

(1) Insulation resistance-dielectric absorption test- 
ing. The insulation resistance test is probably the best 
known and most often used electrical test for insula- 
tion. It is used primarily to detect low resistance paths 
to ground or between windings that result from car- 
bonization, deterioration, or the presence of moisture 
or dirt. It will not indicate the actual quality of the insu- 
lation, but when conducted under controlled condi- 
tions, with the data compiled for a number of service 
intervals, trending data can be developed, and definite 
conclusions can be drawn as to the insulation's rate of 
deterioration. 

(a) High and medium voltage insulation systems 
are usually designed to withstand large potentials and 
large quantities of electricity. Because of this, special 
equipment must be used to perform resistance tests. 
Ohm's Law applies for all systems, and no matter how 
high the applied voltage, or how "resistance" the insu- 
lating material, there will be a measurable leakage cur- 
rent, and there will be a resultant resistance value. 
Because of these conditions, leakage currents are usu- 
ally stated in micro-amps (one millionth of an amp) and 
resistance values in megohms (one million Ohms). 
Most hand-held meters are not capable of reading these 
extremes accurately, and special equipment is used. 
Even if a unit can read these extremes accurately, it 
must also be able to supply the necessary quantities of 
electricity to charge the massive conductors and con- 
tacts found in a transformer. 

(b) An insulation resistance test is usually per- 
formed with a megger, an instrument that is not only 
capable of reading high resistance values, but is also 
able to produce the necessary currents and voltages to 
obtain the readings. Megger test potentials are usually 
applied at 500, 1,000, 2,500, and 5,000 volts DC. These 
potentials are obtained by using a motor driven or 
hand-crank operated magneto. The hand crank units 
are both lightweight and portable, and because they 
require no batteries or external source, they are also 
extremely dependable. Motor-driven units, on the other 
hand, are capable of achieving higher and more con- 
stant test voltages, but are practically useless without 
batteries or an external source. Both units are available 
in models capable of producing accurate readings for 
resistance levels as high as 100,000 megohms. 



(c) The following conditions should be observed 
when performing an insulation resistance test Make 
sure that both the tank and core iron are solidly 
grounded. Disconnect any systems that may be con- 
nected to the transformer winding, including high and 
low voltage and neutral connections, lightning 
arrestors, fan systems, meters, and potential trans- 
formers. Potential transformers are often located on tli 
line sides of breakers or disconnects; when the discon- 
nect is opened, there will still be a path available to 
ground. Short circuit all high and low voltage windings 
together at the bushings connections; jumpers should 
be installed to ground, and no winding should be left 
floating. The ground connection on grounded windings 
must be removed. If the ground cannot be convenient- 
ly removed, the test cannot be performed on that wind- 
ing. Such a winding must be treated as part of the 
grounded circuit. 

(d) Using a megohmmeter with a nunimiun scale 
of 20,000 megohms, measure the insulation resistance 
across the connections as shown in figure 7-1. 

(e) The terminal markings are referenced as fol- 
lows: The L terminal is the line or "Hot" terminal of the 
instrument, where the test potential is generated. The E 
terminal is the "Earth" or ground connection. The G ter- 
minal is the "Guard" terminal; it is used to isolate a cer- 
tain portion of the circuit from the test. 

(f) These test connections are considered the 
bare minimum for a maintenance testing cycle, and 
should be applied only to a transformer that has 
already been in service. They will not detect shorts 
between the individual windings on the high or low 
side. For acceptance testing, or for investigative pur- 
poses, the tests diagramed in figure 7-7 can be applied. 

(g) The test voltages should be as close as pos- 
sible to the voltage rating of the component to which it 
is being applied. Suggested test voltages are found in 
table 7-1. 

(h) All final insulation resistance values should 
be corrected to 20 °C to compensate for varying condi- 
tions at the time of the test, and to allow for compari- 
son of readings taken at different test intervals. The 
winding temperature, and not the atmospheric temper- 
ature, should be used for insulation resistance tests. It 
is important to note that when a transformer is de-ener- 
gized, there is a proportional change between the actu- 
al temperature of the windings and the exterior tank or 
oil temperature indicated by the temperature gauges. 
Average readings should be taken for various points on 
the transformer tank, and then the insulation resis- 
tance readings corrected to 20 °C. This is accomplished 
by applying the conversion factors in table 7-2. 

(i) There are many schools of thought as to what 
is considered an acceptable insulation resistance value, 
A widely accepted rule of thumb for insulation resis- 
tance values is "the kV rating of the item under test plus 
one megohm." This should be considered as a bare min- 



7-2 



TM 5-686 




G 

o 



GRD 




High Winding to Low Winding 
and Ground 



Low Winding to High Winding 
and Ground 



Figure 7-1. Transformer maintenna/re test, diagram. 




$-1 



H3 








q 


? 


( 


i 


HZ 


( 


> 


< 


) 


Ml 


c 


i 


< 
< 
















h, 



High Winding to Ground 
Low Winding Guarded 



High Winding 
to Low Winding 



Low Winding to Ground 
High Winding Guarded 



Figure 7-2. Transformer acceptance test diagram. 



imum value, and any values equal to five times this 
amount should be investigated. If the investigation 
reveals nothing, then the humidity and condition of the 
item under test should be considered. A 10 megohm 
resistance value for a piece of 5 kV equipment should 
not be accepted without investigation, but if the humid- 
ity is high, and the insulation is dirty, that value may be 
acceptable. 

Q) The final criterion for evaluating insulation 
resistance values should be the amount of change from 
the manufacturer's factory test values, or from the last 
test interval. The manufacturer should be contacted if 
any values are significantly lower than the factory 
values. 

(k) To obtain useful data that is indicative of the 
dielectric capabilities of the transformer's insulation, it 
is recommended that a polarization index or dielectric 
absorption ratio be computed for all resistance read- 
ings. The polarization index is determined by holding 
the applied voltage of the megohmmeter constant, and 



taking resistance readings at the end of 1- and 10- 
minute intervals. The apparent increase in the resis- 
tance is due to the dielectric charging of the insulation. 
The polarization index is computed by dividing the 1- 
minute value into 10-minute value. 

(1) The dielectric absorption ratio is computed 
in the same way, except that 60-second intervals are 
used. These values should, theoretically, be indepen- 
dent of temperature or other outside factors. 

(m) The polarization index and dielectric 
absorption ratios are also subject to different methods 
of interpretation. In any case, they should always be 
greater than one, and any downward trend in their 
value over a number of test intervals indicates deterio- 
ration that should be investigated. 

(2) winding resistance measurements. If a mea- 
surement of the winding resistance shows no apprecia- 
ble change from the factory test values, then it can be 
assumed that there are no loose connections. 
Maintenance testing should include only the applied 



7-3 



TM 5-686 



tap position. Three-phase wye windings should be mea- 
sured phase to neutral, and delta windings should be 
separated to read individual windings, if possible. If the 
windings cannot be separated, three separate readings 
should be taken, with each winding measured in paral- 
lel with the other two, and the results evaluated as a 
function of the parallel and series connections 
involved. In this instance, the comparison of the three 
readings (the difference should be no greater than 1 
percent) will indicate whether or not there are any 
problems. 

(a) The winding resistance can be measured 
with a low resistance ohmmeter, or with a Kelvin 
bridge. Be sure to make good contact with the winding 
leads, and to wait 3 minutes after initial contact before 
taking a reading. This delay is necessary due to the 
induction created by the transformer windings. 
Because the windings will store energy, it is important 
to shut off the test set. and allow the energy to dissipate 
before removing the test leads. 

(b) If the factory test values are available, or if 
the transformer cannot be disconnected, the resistance 
values for each winding should be compared to those 
of the adjacent windings. A difference of one percent 
indicates a potential problem. 

(3) Contact resistance. Loose connections can 
result in overheating and possible equipment failure. 
All high and low voltage and ground connections 
should be inspected, and if any abnormal conditions 
are noted, the contact resistance should be measured 
to ensure that solid contact is being made. This testing 
works especially well in conjunction with infrared 
scanning. If a connection shows hot on the IR scan, and 
its contact resistance cannot be lowered by tightening, 
it should be replaced. 

(4) DC high potential testing. The DC high poten- 
tial test is applied at above the rated voltage, and can 
cause damage to the transformer if special precautions 
are not taken. When a leakage current passes through 
the insulation system of an oil-filled transformer, dif- 
ferent amounts of the total voltage are dropped in the 
solid (paper) and liquid (oil) parts of the insulation. 
These voltage drops are caused by the resistance of 
each insulating component, and heat is created. Under 
normal AC operation, only a small amount (1/4) is 
dropped across the solid insulation. The remaining 3/4 
is dropped in the oil, where the heat can be easily dis- 
sipated, and little harm is done. 

(a) When a DC potential is applied, nearly 3/4 of 
the voltage is dropped across the solid insulation. This 
changing stress is further complicated when higher 
than operating level voltages are applied. DC Over- 
potential testing is of little value as a maintenance test, 
and is usually conducted for acceptance purposes, or 
after repair of transformers. In any event, high poten- 
tial testing should not be conducted unless a satisfac- 
tory result is obtained for the insulation resistance. It is 



highly recommended that the manufacturer be contact- 
ed before performing this test, and that only manufac- 
turer's procedures be followed in conducting this test. 
(6) DC Step Voltage Testing is often performed 
on transformers at less than the rated voltage of the 
winding under test. Voltages are applied in equal incre- 
ments at timed intervals (usually 1 minute) and the rate 
of change of the leakage currents is monitored. When 
the applied potential is plotted against the leakage cur- 
rents (on Log-Log paper) Llie rate of change should 
yield a reasonably linear slope. Leakage current jumps 
of more than 100450 percent times the previous value, 
usually indicate a problem, and the test should be dis- 
continued so that the circuit can be investigated. Like 
all of the other tests, this test is especially useful when 
repeated tests over extended time intervals are consid- 
ered, and trending data is generated. 

7-3. Alternating current testing 

AC testing is especially valuable when the trans- 
former's reactive capabilities are to be measured. For 
maintenance testing, this includes power factor testing 
(measuring the capacitive quality of the insulation sys- 
tem) and turns ratio testing (measuring the inductance 
that links the primary and secondary). Although AC 
testing requires more energy to perform at the rated 
frequency, and larger test sets are involved to reach the 
same operating levels as DC, AC testing more closely 
simulates the operating condition of the transformer. 
The following tests are recommended for regularly 
scheduled maintenance: 

a. Transformer turns ratio. The transformer turns 
ratio (TTR) test is used to determine, to a high degree 
of accuracy, the ratio between the primary and sec- 
ondary of the transformer. This test is used to verify 
nameplate ratio, polarity, and tap changer operation for 
both acceptance and maintenance testing. It can also 
be used as an investigative tool to check for shorted 
turns or open windings. If the turn to turn insulation 
begins to break down in either winding, it will show up 
in successive TTR tests. 

(1) Although there are a number of methods avail- 
able, the most accurate method is by the use of a null 
balance test set. The ratio determined by the test set 
should agree with the indicated nameplate voltage 
ratio, within a tolerance of ± 0.5 percent. 

(a) If a high exciting current is developed at low 
voltage, it could indicate a short in the windings or an 
unwanted short across the exciting clamps. 

(6) If there is a normal exciting current and volt- 
age, but not galvanometer deflection, there is the pos- 
sibility of an open circuit or a lack of contact at the test 
leads. 

(<?) Actual test results for most transformers will 
show a slight ratio difference for the different legs of 
the core, due to the different return paths for the 
induced magnetic flux. 



7-A 



TM 5-686 



(2) The transformer ratio can also be computed by 
applying a voltage to the primary, and using two volt 
meters to read the voltage applied to the primary and 
the voltage induced in the secondary. This method 
depends on the combined accuracies of both volt 
meters, and is usually accurate to only about 1 percent. 
b. Insulation power factor. Insulation power factor is 
similar to system power factor, in that it is a ratio of the 
reactive and resistance components (apparent and real 
power) of the applied potential. However, where is is 
desirable to have a system power factor as close as pos- 
sible to one (purely resistance), an insulation's power 
factor is expected to be as near zero (purely capacitive) 
as possible. Insulation power factor is more akin to the 
dissipation factor that is used as a criterion to evaluate 
the efficiency of capacitors. The transformer's insula- 
tion is expected to perform as a capacitor. 

(1) Any time two conductors are at different 
potentials, there is a capacitance between them. There 
is a capacitance between the individual windings, and 
between each winding and the tank in a transformer. 
The oil and cellulose insulation that separate the wind- 
ings from each other and from the tank act as dielectric 
materials when an alternating current is applied. 
Uncontaminated oil and winding insulation are excel- 
lent dielectric materials, and will consume little energy 
in the capacitive charging and discharging that occurs 
in an AC system, this charging current is expressed in 
volt amperes, and under ideal conditions, is complete- 
ly returned to the system in each full cycle. Figure 7-3 
illustrates this relationship. 

(2) The capacitive nature of the insulation changes 
as the oil becomes contaminated. Contaminants con- 
sume energy in the charge/discharge cycle, and this 
energy is lost as heat. Because this power is consumed 
and dissipated as heat, it appears as a resistive compo- 
nent, and can be expressed in watts. The diagram in fig- 
ure 7-3 is modified in figure l-\ to show this resistive 
component. 

Power factor testing is performed by measuring the 
total volt-amperes drawn by the system. A capacitance 
bridge, resistance bridge, or combination of volt, amp, 
and watt meters is used to separate the resistance and 
reactive components. The power factor is then 
expressed as a ratio of the resistive energy that is con- 
sumed as heat (watts), to the apparent (vector sum of 
reactive and resistance) energy that flows into the sys- 
tem (volt-amperes). Figure 7 5 shows a typical meter- 
ing system for measuring power factor. The power fac- 
tor can also be expressed as a function (the cosine) of 
the phase angle between the applied voltage and the 
resulting current. If the insulation was purely resistive, 
the current would occur at exactly the same time as the 
voltage was applied (the phase angle, or displacement, 
between the current and the voltage would be zero). 
The cosine of ° is one, representing a 100 percent 
power factor. 




Figure 7-3. Winding losses in a transformer with 
uncontaminated dielectric. 




Figure 7—i. Winding losses in a transformer with contaminated 
dielectric. 



7-5 



TM 5-686 







VOLTMETER 


4MMETER 





























o E 




6 

w 

909 




00 


r / 

V//. 














1 
i 






\ 






AC 
SOURCE 






WATTMETER 




TEST 

SPECIMEN 



Figure 7-5. Voltmeter-ammeter-wattmeter method of measuring insulation power factor. 



(3) If the insulation were purely capacitive (an 
ideal condition), the voltage would not reach its maxi- 
mum until 90 degrees after the current had already 
reached its maximum. The cosine of 90 degrees is zero, 
representing a zero percent power factor. The ideal sit- 
uation is a purely capacitive insulating quality; the exis- 
tence of a minor resistive component produces a slight 
angular shift or displacement (a marginally acceptable 
power factor of 1 percent corresponds to a phase angle 
of 89.43 degrees, or a displacement from ideal condi- 
tions of 0.57 degrees). 

(4) Any insulating medium will have a measurable 
power factor. Power factor tests are performed on 
transformers, bushings, circuit breakers, and even on 
insulating fluid (a special can is used to provide a con- 
trolled environment). Bushing power factor measure- 
ments are especially useful, and most larger bushings 
have a special voltage tap that provides a standard ref- 
erence point between the conductor and ground. 
Bushings without this tap require a "hot collar" test 
(see figure 7-6), where the potential is applied to the 
outer surface of the bushing material and leakage cur- 
rents are measured through the ceramic or epoxy of 
the bushings material. 

(5) Another application of the power factor test is 
the "tip up" test, where the power factor is measured at 
two different potentials (usually 2.5 and 10 kV) and the 
results are compared. Because the power factor is a 
pure ratio, the results should be independent of the 
applied potential, and any differences will reflect the 
presence of moisture or other impurities that are 
affected differently by different applied potentials. 

(6) The power factor can be measured by a meter- 
ing arrangement, or by using a capacitance or resis- 
tance bridge. The quantities being measured are not 
only small, but they are also quite small in relation to 
each other. Because of these magnitudes, and because 
the power factor is usually determined to the tenth of a 
percent, it is important that the instruments) being 
used have a high degree of accuracy and reproducibili- 




H 



POWER 
FACTOR 
TEST 
SET 



'GROUND 



Figure 7-6. "Hot cottar" busing power factor (est. 

ty. This is best accomplished with a unitized test set. 

(7) Although AC overpotential tests are performed 
on new transformers at the factory (BIL, induced voltage, 
and various loss measurements), they are potentially 
damaging, and are of little value for maintenance pur- 
poses. Also, because an AC test set must be able to 
achieve test potentials at alternating frequencies, rela- 
tively large sets are required to effectively charge and dis- 
charge large transformers. It is recommended that the 
manufacturer be contacted before performing any AC 
tests at above the rated voltage. In any case, the trans- 
former should have already passed the other tests listed 
here, and the possibility of transformer failure should 
always be considered when conducting these tests. 

(8) The true value of tests is realized when con- 
ducted in exactly the same manner, over a number of 
test intervals 



7-6 



TM 5-686 



CHAPTER 8 
TRANSFORMER AUXILIARY EQUIPMENT 



8-1. Auxiliaries 

Even though the transformer is basically a static 
device, many changes in pressure and temperature are 
constantly occurring. The temperature and pressure 
changes must be monitored and their changes compen- 
sated. Also, because of the transformer's high voltage 
and power capabilities, there are areas of extremely 
high voltage stress, and many opportunities for large 
surges and fault conditions. The following auxiliary 
equipment is used to monitor and compensate for 
many of these factors, and can be found on most power 
transformers. 

8-2. Bushings 

The leads from the primary and secondary windings 
must be safely brought through the tank to form a ter- 
minal connection point for the line and load connec- 
tions. The bushing insulator is constructed to minimize 
the stresses at these points, and to provide a conve- 
nient connection point. The bushing is designed to 
insulate a conductor from a barrier, such as a trans- 
former lid, and to safely conduct current from one side 
of the barrier to the other. Not only must the bushing 
insulate the live lead from the tank surfaces, but it must 
also preserve the integrity of the tank's seal and not 
allow any water, air, or other outside contaminants to 
enter the tank. 

a. There are several types of bushing construction; 
they are usually distinguished by their voltage ratings, 
although the classifications do overlap: 

Solid (high alumina) ceramic — (up to w5kV) 
Porcelain— oil fdled (25 to 69kV) 
Porcelain — compound (epoxy) filled (25 to 69kV) 
Porcelain — synthetic resin bonded paper-filled (34.5 

to 115kV) 
Porcelain — oil-impregnated paper-filled (above 69kV, 

but especially above 275kV) 

b. For outdoor applications, the distance over the 
outside surface of the bushing is increased by adding 
"petticoats" or "watersheds" to increase the creepage 
distance between the line terminal and the tank. 
Contaminants will collect on the surfaces of the bush- 
ing and form a conductive path. When this creepage 
distance is bridged by contaminants, the voltage will 
flashover between the tank and the conductor. This is 
the reason why bushings must be kept clean and free of 
contaminants. 



c. Transformer bushings have traditionally been 
externally clad in porcelain because of its excellent 
electrical and mechanical qualities (see figure 8-1). 
Porcelain insulators are generally oil-filled beyond 35 
kV to take advantage of the oil's high dielectric 
strength. There are a number of newer materials being 
used for bushings, including: fiberglass, epoxy, synthet- 
ic rubbers, Teflon, and silica compounds. These mate- 
rials have been in use for a relatively short time, and 
the manufacturer's instructional literature should be 
consulted when working with these bushings. 

d. Maintenance. Bushings require little maintenance 
other than an occasional cleaning and checking the 
connections. Bushings should be inspected for cracks 
and chips, and if found, should be touched-up with 
Glyptal paint or a similar type compound. Because 
bushings are often called on to support a portion of the 
line cable's weight, it is important to verify that any 
cracks have not influenced the mechanical strength of 
the bushing assembly. 

e. Testing. Most bushings are provided with a voltage 
tap to allow for power factor testing of the insulator. If 
they have no tap, then the power factor test must be 
performed using the "hot collar" attachment of the test 
set. The insulation resistance-dielectric absorption test 
can also be performed between the conductor and the 
ground connection. 

8-3. Pressure relief devices 

When the transformer is overloaded for extended peri- 
ods, or when an internal fault occurs, high pressures 
will occur in the tank. There are a number of devices 
used to accommodate this pressure change. 

a. Pressure relief valves. Pressure relief valves are 
usually installed behind the pressure gauge on sealed 
tank units. They are used in conjunction with pressur- 
ized nitrogen systems and can be mounted in the gas 
bottle cabinet or on the tank wall. The bleeder valve is 
set to bleed-off any pressures that exceed a pre-set 
level (usually around 8-10 psi). This valve is an integral 
part of the pressurized gas system, and its failure can 
result in a rupture of the tank. 

b. Pressure relief valve testing. The operation of 
these devices can be checked b manually increasing 
the tank pressure to the pre-set level. It is important not 
to exceed the maximum tank pressure. If the valve 
does not bleed off the excess pressure, it should be 
replaced. 



8-1 



TM 5-686 





Figure 8-1. Transformer porcelain and oil filled bushings. 



c. Mechanical pressure-relief devices. These devices 
relieve sudden or accumulated internal pressure at a 
predetermined value. They are usually mounted on the 
top of the tank, and consist of a diaphragm, a spring- 
loaded mechanism, and an indicating flag (see figure 
8-2). When the pressure exceeds a preset level, the 
diaphragm is raised and the excess pressure is bled off. 
The indicating flag remains raised, so that the occur- 
rence will be noted during the next inspection cycle. 
Some pressure relief devices are also equipped with 
contacts that are used to actuate external relays, 
alarms, or circuit breakers, the space above the tank 
must be purged with dry nitrogen, and the diaphragm 
reset any time a relief device is found with its indicat- 
ing flag popped. 

d. Mechanical pressure relief valve testing. A 
mechanical pressure relief device cannot be tested 
without removing it from the tank. Since removal is 
impractical, it should be inspected regularly to ensure 
there are no cracks in the diaphragm and that the 
diaphragm/spring mechanism is free to operate. The 
operation of any relay contact and the associated con- 
trol wiring should also be checked periodically. 



e. Relief diaphragms. Relief Diaphragms are usually 
found on conservator type transformers. Relief 
diaphragms consist of a bakelite, thin metal, or glass 
diaphragm mounted on a large pipe that extends above 
the level of the conservator tank. The diaphragm mate- 
rial is designed to rupture at a predetermined pressure 
level. Other than inspecting for evidence of rupture, 
there is little or no maintenance to be performed on 
these devices. Relief diaphragms must be replaced 
after rupturing. 

f. Sudden pressure relays. These devices consist of 
a bellows, a small orifice, and a set of relay contacts 
that are slaved to the mechanical movement of the bel- 
lows (see figure 8-3). When the transformer undergoes 
the pressure changes experienced during normal oper- 
ation, the small orifice bleeds off the pressure, and the 
bellows will not move. When an arc or an internal fault 
occurs, the large volume of gas generated over rela- 
tively short time frame pushes on the bellows and actu- 
ates the contacts. The contacts are used to actuate an 
alarm, a circuit breaker, or another relay. There are 
variations in the design of sudden pressure relays, but 
they all operate on the same basic principle. Sudden 



8-2 



TM 5-686 




1. Diaphragm 

2. Inside gasket 

3. Outside gasket 

4. Mounting gasket 

5. Base 

6. Cover support stud 

7. Cover 

8. Cover boh) 
g. Large spring 



tng 

11. Indicator- tripped position 

12. Rating namepfate 

13. Alarm switch (optional) 

14. Plug for switch mounting 

15. Switch reset lever 
15. Mounting bott 
17. Mounting flange 
IB. tank cover 



Figure 8-2. Mechanical pressure relief device. 



pressure relays are not actuated by any set pressure 
level; they operate when the rate of change of pressure 
exceeds a preset value. Because arcing or internal 
faults generate large quantities of gas, over a short peri- 
od of time sudden pressure relays are effective in 
detecting fault conditions. Sudden pressure relays pro- 
vide little protection against over-pressure tank condi- 
tions occurring over an extended time period. 

g. Sudden pressure relay testing. The sudden pres- 
sure relay is usually mounted in the gas space above 
the oil level, and it is important to ensure that oil does 
not enter the unit. The operation of the relay is verified 
by checking that the orifice remains open, and that the 
bellows is free to move. The control wiring and the con- 
tact operation should also be verified. 

8^4. Pressure gauges 

Most transformers are equipped with a pressure gauge. 
The gauge assembly consists of a pressure sensitive 
element (a bulb or a diaphragm), an indicator attached 
to the element, and a dial calibrated for the required- 
vacuum range of the tank. Although there is little or no 
maintenance to be performed on a pressure gauge, its 
operation should be verified if no changes are noted 
during a number of inspection intervals. 

8-5. Temperature gauges 

Temperature gauges are either of the "hot spot" or 
"average tank temperature" type. There are many 
designs in use. Most average tank temperature gauges 
consist of a spiral wound bi-metallic element that is 
directly coupled to a dial-type indicator. 



a. Both average reading and hot spot temperature 
gauges can use a bulk-type detecting unit that is 
immersed in the oil either near the top of the oil level 
(see figure 8-4), or near the windings at the spot that 
is expected to be the hot test. A capillary tube is con- 
nected to the bulb and brought out of the tank. The 
temperature indication is provided either by a linear 
marking on the tube itself, or by a dial-type indicator. 
Dial-type gauges can have up to three sets of contacts 
that will actuate any of the following devices: 

(1) The lowest setting usually actuates external 
cooling fans that will come on at a preset temperature 
level. The fans will shut off once the temperature has 
been reduced to the prescribed level. 

(2) The contacts can also be set to actuate remote 
alarms that will alert maintenance personnel of the 
condition of the transformer. These devices must be 
reset even though the temperature has returned to 
normal. 

(3) The highest and most critical contact setting 
on the temperature gauge is connected to a relay or a 
circuit breaker that will trip out and de-energize the 
transformer. 

b. Most dial-type gauges (see figure 8-5) are 
equipped with a red indicating needle that has no 
spring return and will indicate the highest tempera- 
ture seen since it was last reset. This slaved hand nee- 
dle reading should be recorded for each inspection 
interval, and the needle should be reset to ambient 
temperature so that it will indicate the maximum tem- 
perature for the next inspection interval. 



8—3 



TM 5-686 




1. SWITCH 

2. ROCKER ARM 

3. CONTROL BELLOW 

4. ORIFICE AND COMPENSATOR 

5. BLEEDER VALVE 

6. TEST PLUG 

7. RECEPTACLE 



ACUATOR 
SPRING 



10. CONTROL BELLOWS 

11. SILICONE OIL 

12. TRANSFORMER INSULATING LIQUID 

13. SENSING BELLOWS 



Figure 8-3. Sudden pressure relay. 



8-6. Tap changers 

As noted in chapter 3, transformers are often required 
to operate under changing primary voltages, or to pro- 
vide a number of different secondary voltages. Most 
transformers are equipped with a tap changer (see fig- 
ure 8-6), and any number of taps can be brought off of 
either of the windings to accomplish this voltage 
change. Tap changers can be conveniently divided into 
two categories: no-load tap changers and load tap 
changers. 

a. No-load tap changers. No-load tap changing is 
usually accomplished on the primary side of a step- 
down power transformer. The taps are usually provid- 
ed 2-1/2 percent intervals above and below the rated 
voltage, nd the transformer must be de-energized 
before the tap position can be changed. The taps are 
changed either by turning a hand wheel, moving a 
selector switch, or lowering the oil level, opening the 
manhole, and actually reconnecting the winding leads 
to various positions on a terminal board. No-load tap 
changers are usually used to accommodate long-term 
varitions in the priamry voltage feed. 



b. Load tap changers: Load tap changers are usually 
located on the secondary side of the transformer. They 
are used to control the current and voltage as the load 
is varied. Load tap changing transformers are used 
especially for furnace applications, and to regulate the 
changing voltages found in large substations. 

(1) Because load tap changers are required to open 
and close the circuit while it is hot, they incorporate a 
numbe of devices to minimize the switching time and 
the amount of energy (the arc) released. Some tap 
changers use vacuum bottle type breakers to interrupt 
the current flow, while others use a conventinal 
main/arcing contact mechanism, much like that found 
in a circuit breaker. Other tap changers use resistor or 
reactor circuitry in the mechanism to limit the current 
flow at the time the switching occurs. Load tap chang- 
ers can be either automatic or manual, and can be used 
to vary the voltage and current by as much as 2 or 3 per- 
cent , depending on application. 

(2) Most load tap changers are immersed in oil and 
are contained in a separate compartment from the pri- 
mary and secondary windings. Because of the large 



8-4 



TM 5-686 



WELL 



- TEMPERATURE 
INDICATOR 
BULB 




HANDHOLE ■ 



TEMPERATURE 
INDICATOR- 



MAXIMUM 
INDICATING 
POINTER 
RESET 



ALARM LEADS 




-TO CURRENT 
TRANSFORMER 



-TANK WALL 



A . ROTATING CONNECTION 

B . RODS 

C . POINTER 

D . DIAL 

E . KNOB 

F . STOP 




Figure 8-4. Temperature gauge. 



Figure 8-6. Schematic diagram of transformer tap changer. 

amounts of energy (switching arcs) produced, the oil in 
the tap changing compartment deteriorates at a much 
faster rate than the oil in the main compartment. 

c. Tap changer testing. The tap changer's operation 
is varieifed by performing a turns ratio test at the vari- 
ous tap settings. This holds true for both the no load 
tap changers. The arcing contact or vacuum bottle 
assemblies for the load tap changers should be inspect- 
ed, and the contact resistance should be measured if 
there is evidence of putting or contact wear. Because of 




COVER SCREW FOR MAX 
POINTER RESET STEM. TO 
RESET MAX POINTER 
REMOVE CAP AND PULL 
DOWN ON RESET STEM. 

S4" OF NEOPRENE 
COVERED CABLE SUPPLIED 
WITH ALARM THERMOMETERS 



NOT TO EXCEED 
2 1/2" 



CAPILLARY TUBING 



Figure 8-5. Dial type temperature gauge. 



8-5 



TM 5-686 



the switching activity, the oil in the tap changer com- 
partment should be sampled and analyzed twice as 
often as the main tank oil. 

8-7. Lightning (surge) arresters 

Most transformer installations are subject to surge volt- 
ages originating from lightning disturbances, switching 
operations, or circuit faults. Some of these transient 
conditions may create abnormally high voltages from 
turn to turn, winding to winding, and from winding to 
ground. The lightning arrester is designed and posi- 
tioned so as to intercept and reduce the surge voltage 
before it reches the electrical system. 

a. Construction. Lightning arresters ar similar to nig 
voltage bushings in both appearance and construction. 
They use a porcelain exterior shell to provide insula- 
tion and mechanical strength, and they use a dielectric 
filler material (oil, epoxy, or other materials) to 
increase the dielectric strength (see Figure 8-7). 
Lightning arresters, however, are called on to insulate 
normal operating voltages, and to conduct high level 
surges to ground. In its simplest form, a lightning 
arrester is nothing more than a controlled gap across 
which normal operating voltages cannot jump. When 
the voltages exceeds a predetermined level, it will be 
directed to ground, away from the various components 
(including the transformer) of the circuit. There are 
many variations to this construction. Some arresters 
use a series of capacitances to achieve a controlled 
resistance value, while other types use a dielectric ele- 
ment to act as a valve material that will throttle the 
surge current and divert it to ground. 

b. Maintenance. Lightning arresters use petticoats to 
increase the creepage distances across the outer sur- 
face to ground. Lightning arresters should be kept 
clean to prevent surface contaminants from forming a 
flashover path. Lightning arresters have a metallic con- 
nection on the top and bottom. The connectors should 
be kept free of corrosion. 

c. Testing. Lightning arresters are sometimes con- 
structed by stacking a series of the capacitive/dielectric 
elements to achieve the desired voltage rating. Power 
factor testing is usually conducted across each of the 



INSumTWS TEFWINAL CAP 




HKSHSTOENG1H 
WETmoCESS 
QIAZED PCflCELAW 



> ALUMINUM SPACER 



SOUIOH'" 

GFKXX4DL£>£ 

DISCONNECTOR 



Figure 8-7. Lightning arresters. 

individual elements, and, much like the power factor 
test on the transformer's windings, a ratio is computed 
between the real and apparent current values to deter- 
mine the power factor. A standard insulation resis- 
tance-dielectric absorption test can also be performed 
on the lightning arrester between the line connection 
and ground. 



8-6 



TM 5-686 



CHAPTER 9 
COMPREHENSIVE MAINTENANCE/TESTING PROGRAM 



9-1. Transformer maintenance 

Of all the equipment involved in a facility's electrical 
distribution system, the transformer is probably the 
most neglected. A transformer has no moving parts; 
consequently it is often considered maintenance-free. 
Because the transformer does not trip or blow when 
oven-stressed (except under extreme conditions), it is 
frequently overloaded and allowed to operate well 
beyond its capacity. Because the transformer is usually 
the first piece of equipment on the owner's side of the 
utility feed, it usually operates at much higher voltages 
than elsewhere in the facility and personnel are not 
anxious to work on or around it. The fact that a trans- 
former has continued to operate without the benefit of 
a preventive maintenance/testing program says much 
about the ruggedness of its construction. However, a 
transformer's ruggedness is no excuse not to perform 
the necessary testing and maintenance. 

a. Any piece of electrical equipment begins to deteri- 
orate as soon as it is installed. The determining factor 
in the service life of a transformer is the life of its insu- 
lation system. A program of scheduled maintenance 
and testing cannot only extend the life of the trans- 
former, but can also provide indications of when a 
transformer is near the end of its service life, thus 
allowing for provisions to be made before an 
unplanned failure occurs. Also, a transformer checked 
before a failure actually occurs can usually be recondi- 
tioned or refurbished more easily than if it had failed 
while on line. 

b. There are many benefits to a comprehensive main- 
tenance and testing program: 

(1) Safety is increased because deficiencies are 
noted and corrected before they present a hazard. 

(2) Equipment efficiency is incrased because con- 
ditions that ultimately increase the transformer's losses 
can be corrected. 

(3) If a problem occurs, it can usually be rectified 
more quickly because service records and equipment 
information are centrally located and readily available. 

(4) As the power requirements of a facility grwo, 
any overloaded or unbalanced circuits will be detected 
more quickly, allowing for adjustments to be made 
before any damage is incurred. 

(5) If impending failures are discovered, the repair 
work can be scheduled during off-peak hours, reducing 
the amount of inconvenience and expense. 



c. To realize these benefits, a comprehensive plan 
must be thoughtfully developed and diligently adminis- 
tered. Although the generalized needs of transformers 
are addressed here, depending on construction and 
application, transformers may need more or less fre- 
quent attention than specified here. Once again, thers 
are simply guidelines, and in no instance should the 
manufacturer's recommendations be neglected. 

9-2. Maintenance and testing 
program 

A comprehensive maintenance and testing program is 
instituted for a number of reasons and benefits. The 
objective of a comprehensive program is not just to get 
the work done, but to ensure that the work is complet- 
ed according to a methodical and priority-oriented pain 
of action, A comprehensive program ensures that all 
maintenance needs are fulfilled, and that testing and 
inspections are performed to verify that the equipment 
is not deteriorating at an accelerated rate. By docu- 
menting all activities and performing the work as part 
of an overall plan, the program also helps to eliminate 
any redundancies or duplication efforts. There are five 
basic activities involved in a comprehensive program: 

a. Inspections. Inspections do not require an outage, 
and can therefore be performed more frequently than 
most other maintenance functions. Inspections are a 
very effective and convenient maintenance tool. If 
inspections are carefully performed along with an oil 
analysis they can reveal many potential problems 
before damage occurs. A transformer inspection 
should include all gauge and counter readings, the 
operating conditions of the transformer at the time of 
the inspection, a check of all auxiliary equipment, the 
physical condition of the tank, and any other visible 
factors that affect the operation of the transformer. 
Inspections should be conducted on a weekly basis, 
and should be thoroughly documented and stored with 
the transformer's service records. 

b. Infrared (IR) Imaging. Infrared imaging is also an 
effective inspection tool. Loose connections, unbal- 
anced loads, and faulty wiring will all emit relatively 
higher levels of heat than their surroundings, infrared 
imaging systems provide a screen display (like a TV) 
that shows the temperature difference of the items on 
the screen. It is the relative difference in temperature, 
and not the actual temperature that will indicate any 



9-1 



TM 5-686 



problems. If the IR scan is performed annually, it 
should be performed 6 months after the annual mainte- 
nance outage, to maximize prtection between the 
hands-on service intervals. 

c. Sampling. Drawing samples of the transformer's 
fluid provides the opportunity to actually remove a por- 
tion of the transformer's insulation and subject it to a 
battery of standardized tests, under controlled labora- 
tory conditions, with the benefit of complex laboratory 
equipment. Most transformers can be sampled while 
energized, so there is no major inconvenience involved. 
Although samples should be taken more frequently at 
the outset of a program (every 6 months), once the 
baseline data and the rate of deterioration have been 
determined, the frequency can usually be adjusted 
according to the needs of the transformer (normally 
once a year). 

d. Maintenance. Most maintenance functions 
require an outage since they present a hazard to the 
personnel involved. Maintenance functions involve 
periodic actions that are performed as a result of the 
expected wear and tear and deterioration of the trans- 
former. They include wiping down all bushings and 
external surfaces, topping off fluids, tightening connec- 
tions, reconditioning deteriorated oil, recharging gas 
blankets and checking gas bottles, touching-up the 
paint, fixing minor leaks, and doing any maintenance 
required for fan systems and tap changer systems. Most 
of these operations should be performed annually, 
when the transformer is de-energized for testing. 

e. Testing. Testing provides functional verification of 
the condition of the transformer. All transformer test- 
ing requires an outage. The tests that should be per- 
formed on a regularly scheduled basis are: Power fac- 
tor, Insulation resistance-Dielectric absorption, Turns 
ratio and Winding resistance. Testing is an important 
part of a comprehensive program because it uses elec- 
tricity to verify the operating condition of the trans- 
former. Most outdoor transformers should be tested 
annually, although lightly loaded transformers in favor- 
able environments can get by with testing every 3 
years. More frequent testing should be performed at 
the outset of a program to determine the specific trans- 
former's needs. 

/ Repair. Although there is little distinction between 
maintenance and repair activities, the planned or 
unplanned nature of the work will usually determine its 
category. The whole idea of the comprehensive pro- 
gram is to minimize the amount of unplanned down- 
time necessary for repairs. When the deterioration of 
the transforme's oil is monitored, and arrangements are 
made to recondition the oil during a planned outage, it 
can be called a maintenance function. When a tran- 
former fault occurs, and subsequent testing reveals 
that the oil is unift for service, the unplanned oil recon- 
ditioning becomes a repair function; in this case, there 
is a much more significant inconvenience factor. 



9-3. Documentation 

Performing the work on the transformer is all well and 
good, but the information gained is practically useless; 
if it cannot be easily accessed and compared to other 1 
test results. To ensure that all inspection, test, analysis, 
maintenance, and repair data can be used most effec- 
tively, the data must be properly documented and read- 
ily accessible. This usually involves keeping records of 
all activities in a centralized filing system. 

a. Although the technician performing the work is 
ultimately responsible for getting the information on 
paper, a properly constructed record will not only help 
the technician, but will also help the personnel respon- 
sible for organizing and storing the data. Every record, 
whether it is an inspection, test, or repair record should 
have as much information about the transformer and 
the test conditions as possible. This includes the man- 
ufacturer, the kVA rating, the serial number, and the 
voltage ratings. There should also be space on the 
record to note the temperature, humidity, and weather 
conditions at the time of the activity. Another factor 
that can be extremely important is the loading condi- 
tions immediately prior to (for de-energized activities) 
or during (for inspections or sampling) the service pro- 
cedure. All of this information can be extemely helpful 
for interpreting the results. 

b. Several factors should be tanken into considera- 
tion when devising a maintenance program for a spe- 
cific transformer. The two most important factors are 
the environment in which the transformer is operating 
and the load to which it is being subjected. Although 
the exact effect these conditions will have on the trans- 
former may not be known at the outset, the rate of 
deterioration should be determined by the end of the 
first year of the program and any adjustment can be 
made after that. 

9-4. Scheduling 

It is very easy to prescribe maintenance and testing, 
and most facilities management personnel will agree to 
the benefits of the program. It is when the outage must 
be obtained to perform the work that the problems 
arise. This is where the comprehensive part of the pro- 
gram comes into play. It is the responsibility of the 
maintenance department to work with all the depart- 
ments involved to schedule the necessary outages. 

a. Once all involved parties have decided to institute 
a preventive maintenance and testing program, the 
maintenance needs of the transformer and the avail- 
ability of the outages necessary to perform the work 
must be considered. Because the power transformer 
usually affects a large portion of the electrical service 
to a facility, scheduling outages can be extremely diffi- 
cult. Quite often, the work must be performed at night 
or during off-peak hours over the weekend. Although 
this can sometimes cause major inconveniences, the 



9-2 



TM 5-686 



work must be performed, and the biggest help the 
maintenance personnel/department can provide is to 
minimize the time required for the outage. 

b. Except for visual inspections, infrared (IR) inspec- 
tions and sampling, all transformer maintenance/test- 
ing procedures require an outage. Unless there are 
redundant sytems such as generators and alternate 
feeds, the outage will black out portions of the facility. 
It is important that all equipment be assembled and 
prepaations be made before the switch is thrown. This 
includes having all the necessary test equipment and 
spare parts on hand. Although it may be difficult to esti- 
mate the amount of time each service procedure will 
require, as the program is implemented, these factors 
will be easier to estimate, and they will be performed 
more quickly as the maintenance personnel become 
more experienced. 

c. The transformer should be inspected on a weekly 
basis. This inspection should be thoroughly document- 
ed, and should include all gauge readings, load cur- 
rents, and the visual condition of all the transformer's 
auxiliary equipment. If unexplained maximum temper- 
atures occur or if there is an accelerated deterioration, 
daily inspections, or the use of load recording instru- 
ments should be considered. Infrared scanning can 
also be performed without an outage. The IR scan 
should be performed every 6 or 12 months, depending 
on the transformer type and application. 

d. The transformer's insulating fluid should be sam- 
pled every 6 months during the first year of the pro- 



gram and annually for the remainder of its service life. 
If problems are noted, or if the oil begins to deteriorate 
at an accelerated pace, the transformer should be sam- 
pled more frequently. Tap changers and auxiliary 
switching compartments should also be sampled more 
frequently. The information for each sampling interval 
should be transcribed onto a record that will allow easy 
trending analysis, if an outside contractor is called into 
to perform the sampling and analysis, the record 
should include the smaple information shown, espe- 
cially the atmospheric conditions at the time of the test. 
e. The comprehensive maintenance and testing pro- 
gram will be most effective if the various electrical 
tests are coordianted by a central department. The test- 
ing and maintenance of equipment other than, trans- 
formers in the fcility's electrical distribution system 
should be integrated into an overall program, by cen- 
tralizing the maintenance activities for all of the facili- 
ty's electrical equipment, other items in each individual 
circuit can be investigated to help explain any prob- 
lems being experienced on a specific piece of equip- 
ment. Centralizing the various inspection/tesl/repair 
records also promotes the development of trending 
data, and the analysis of test data over a number of Lest 
intervals. This centralized filing system should also be 
used to generate schedules and to plan activities. If 
possible, a computerized system should be used to gen- 
erate schedules and to plan activities. If possible, a 
computerized system should be established to indicate 
when the items in the sytem are due for service. 



9-3 



TM 5-686 



CHAPTER 10 
STATUS OF TRANSFORMER MONITORING AND DIAGNOSTICS 



10-1. Introduction 

As a key component of all AC power systems, a prop- 
erly functioning power transformer is essential for 
maintenance system integrity. Consequently, new and 
improved monitoring and diagnostic techniques contin- 
ue to be developed to minimize unplanned system out- 
ages and costly repairs. 

1 0-2. Transformer monitoring 

For the purposes of this section, monitoring refers to 
on-line measurement techniques, where the emphasis 
is on collecting pertinent data on transformer integrity 
and not on interpretation of data. Transformer moni- 
toring techniques vary with respect to the sensors 
used, transformer parameters measured, and measure- 
ment techniques applied. Since monitoring equipment 
is usually permanently mounted on a transformer, it 
must also be reliable and inexpensive. 

a. To minimize costs, it is important to minimize the 
number of measurements taken. It is therefore neces- 
sary to identify parameters that are most indicative of 
transformer condition. Consequently, selection of these 
parameters must be based on failure statistics, as 



shown in figure 10-1. The pie chart shows typical fail- 
ure distribution of transformers with on-load tap 
changers (OLTC). As indicated, winding and OLTC fail- 
ures dominate; consequently, the focus of most moni- 
toring techniques is to collect data from parameters 
that can be used to assess the condition of winding and 
tap changers. Dissolved gases in oil and partial dis- 
charges (PD) are common parameters monitored relat- 
ed to winding and insulation condition. Temperature 
and vibration monitoring are commonly used for 
assessing OLTC condition. 

b. Dissolved Gases in oil: As mentioned in paragraph 
5-3 of this manual, dissolved gas-in-oil analysis is an 
effective diagnostic tool for determining problems in 
transformer operation. However, this analysis is typi- 
cally performed off-post, where sophisticated (and usu- 
ally expensive), equipment is used to determine gas 
content. To reduce the risk of missing incipient faults 
due to long sampling intervals, monitoring techniques 
are being developed to provide warnings with respect 
to changes in gas types and concentrations observed 
within a transformer. Conventional dissolved gas-in-oil 
analysis is performed after a warning is issued. Several 





core 




terminals 


3% 




12% 






accessories / ^ 
12% / 




^ OLTC 

\ 41% 


tank/fluid \ a 






13% ^^ 


windings 
19% 





Figure 10-1. Typical failure distribution for substation transformers. 



10-1 



TM 5""686 



transformer gases and corresponding sources are listed 
in Table 10-1. 

c. The main challenges to on-line gas monitoring are 
not only to develop accurate and low cost sensors, but 
sensors that are versatile enough to detect the pres- 
ence of multiple gases. Several new sensor technolo- 
gies are now commercially available to measure con- 
centration changes of multiple gases, and many more 
are in development. The HYDRAN technology for 
example, by Syprotec Inc. (Montreal, Quebec), uses a 
selectively permeable membrane and a miniature elec- 
trochemical gas detector to measure the presence of 
hydrogen, carbon monoxide, ethylene and acetylene 
dissolved in oil. The chemical reactions, which result 
when these gases permeate through the membrane and 
mix with oxygen, generate electrical current that is 
measured as a voltage drop across a load resistor. This 
voltage drop is used to determine a composite parts- 
per-million value of the four gases. This technology is 
used to detect change in gas concentrations only. If 
change is detected, an alarm is triggered, which indi- 
cates that an an oil sample should be taken from the 
transformer and analyzed to evaluate the nature and 
severity of the fault. The Transformer Gas Analyzer, 
developed by Micromonitors, is also designed to detect 
hydrogen, carbon monoxide, ethylene, and acetylene in 
mineral oil-filled transformers. The instrument oper- 
ates on a real-time basis with sensors immersed direct- 
ly in the oil inside the transformer, and is based on 
metal insulator semiconductor technology. The AMS- 
500 PLUS, by Morgan Shaffer Company, measures both 
dissolved hydrogen and water continuously, on-line. 
Asea Brown Boveri is developing sensors based on 
metal oxide technology; however, these sensors are 
still in the field prototype stage. 

(1) Partial Discharges: The most common method 
for on-line detection of partial discharges (PD) is the 
use of acoustical sensors mounted external to the 
transformer. One example of a commercially available 
acoustic emission monitoring instrument is the Corona 
500, by NDT International, Inc., which is designed to 
detect partial discharge of electrical transformers 
while on-line. The main difficulty with using acoustical 
sensors in the field, however, is in distinguishing 



between internal transformer PD and external PD 
sources, such as discharges from surrounding power 
equipment. An alternative method has been proposed 
recently to differentiate between internal and external 
PD, and is based on the combined use of signals from a 
capacitive tap and signals from an inductive coil fitted 
around the base of the bushing. A warning signal is pro- 
vided if PD activity develops inside the tank; therefore, 
this technique does not indicate the seriousness of the 
internal defect. 

(2) Temperature. The load capability of a trans- 
former is determined by the maximum allowable hot 
spot temperature of the winding. Hot spot values Eire 
usually calculated from measurements of oil tempera- 
tures and load current. A more expensive technique is 
to use distributive fiber optic temperature sensors 
Since tap changer condition is a key transformer com- 
ponent, another method consists of metering and mon- 
itoring the differential temperature between the main 
tank and tap changer compartment. This method can 
be used for detecting coking of contacts. For example, 
the Barrington TDM-2L, by Barrington Consultants 
(Santa Rosa, CA), measures oil temperature in the tap 
changer compartment and in the main tank. This tech- 
nology is designed to interface with a SCADA system 
and also provides local digital indication for main tank, 
OLTC, differential, peak and valley oil temperatures. 

(3) Vibration: Vibration monitoring has also been 
proposed for detecting mechanical and electrical faults 
in the OLTC compartments. The method is still under 
development, but could prove to be an effective tech- 
nique for detecting OLTC mechanical problems such as 
failing bearings, springs, and drive mechanisms, as well 
as deteriorating electrical contracts. 

(4) Other Methods: Recently, there has been a con- 
siderable amount of research effort focused on improv- 
ing the intelligence of transformer monitoring systems. 
The approach is to compare the results of actual mea- 
surements for example, using the sensors mentioned 
above) with predictions obtained through simulation 
models. Model parameters are determined to best fit 
past transformer measurements. For normal trans- 
former operation, simulation results should match the 
results obtained from actual measurements. However, 



Table 10-1. Transformer gases and corresponding sources. 



Hydrogen 


Corona, partial discharge, 


Oxygen, nitrogen 


Water, rust, poor seals 


Carbon monoxide, carbon 


Cellulose breakdown 


Methane, ethane 


Low temperature oil 


Ethylene 


High temperature oil 


Acetylene 


Arcing 



10-2 



TM 5-686 



measurements deviating from predictions may indicate 
a problem with the transformer. The claim is that this 
technique can provide very sensitive measures of trans- 
former performance. For example, the Massachusetts 
Institute of Technology uses adaptive mathematical 
models of transformer subcomponents that tune them- 
selves to each transformer using parameter estimation. 
They have used the model-based approach for accurate 
on-line prediction of top oil temperature, which has 
been verified using data from a large transformer in 
service. Of course, other performance predictions can 
be made using appropriate measurable quantities such 
as dissolved gas content. 

10-3. Transformer diagnostics 

For the purposes of this section, diagnostics refers t the 
interpretation of data and measurements that are per- 
formed off-line. Diagnostics are used as a response to 
warning signals and to determine the actual condition 
of a transformer. Since it is not a permanent part of a 
transformer, diagnostic equipment is typically much 
more sophisticated and expensive than monitoring 
equipment. 

a. Dissolved gas-in-oil analysis is the most common 
method for incipient fault detection. This section will 
focus on discussing the results of two research efforts 
including: (1) an expert system approach based on dis- 
solved gas analysis; and (2) an artificial neural network 
approach to detect incipient faults. 

b. Expert System Approach. The analysis of the mix- 
ture of faulty gases dissolved in transformer mineral oil 
has been recognized for many years as an effective 
method for the detection of incipient faults. Experts 
from industry, academia, and electric utilities have 
reported worldwide on their experiences, and have 
developed criteria on the basis of dissolved gas analy- 
sis (DGA). The objective of one expert system 
approach is to develop a rule-based expert system to 
perform transformer diagnosis similar to a human 
expert. Results from a prototype expert system based 
on DGA has been published. The main difficulty to be 
overcome is transforming qualitative human judgments 
into quantitative expressions. The prototype expert 
system uses fuzzy-set models to facilitate this transfor- 
mation. In short, the fuzzy-set model is used for repre- 
senting decision rules using vague quantities. For 



example, the prototype system uses a fuzzy set to man- 
age three diagnostic uncertainties, including: norms, 
gas ratio boundaries, and key gas analysis. Results 
from the prototype study indicate that an expert sys- 
tem could be a useful tool to assist maintenance per- 
sonnel. 

c. Artificial Neural Network Approach: With a similar 
focus as the expert system and fuzzy-set approach, 
researchers are also using artificial neural networks 
(ANN) to reveal some of the hidden relationships in 
transformer fault diagnosis. Very complex systems can 
be characterized with minimal explicit knowledge 
using ANNs. The relationship between gas composition 
and incipient-fault condition is learned by the ANN 
from actual experience. The aim of using ANN is to 
achieve better diagnosis performance by detecting rela- 
tionships that are not apparent (that is, relationships 
that might otherwise go unnoticed by the human eye). 
For example, cellulose breakdown is a source of car- 
bon monoxide; however, overheating, corona and arc- 
ing all cause this type of breakdown. The primary diffi- 
culty is in identifying and acquiring the data necessary 
for properly training an ANN to recognize certain com- 
plex relationships. The more complex a relationship is, 
the more training data are needed. The study presented 
in th Zhang, Ding, Liu, Griffin reference used five gases 
as input features including, hydrogen, methane, ethane, 
ethylene, and acetylene. The results of the study look 
promising, and indicate that the reliability of trie ANN 
approach might be improved by incorporating DGA 
trend data into ANN training, such as increasing rates 
of gas generation. 

10-4. Conclusions 

Several new on-line monitoring technologies are now 
commercially available, and more are in development. 
Research is being conducted that is focused on provid- 
ing on-line diagnostic capability using model-based 
techniques, A trend toward developing more accurate 
and effective incipient fault diagnostics, based on past 
experience with dissolved gas-in-oil analyses, is evi- 
dent from the recent development of expert systems 
and artificial neural networks. As sensor technology 
and interpretation skills mature, it is likely that a shift 
will be made toward performing on-line diagnostics. 



10-3 



TM 5-686 

APPENDIX A 
REFERENCES 



Related Publications 

American National Standards Institute (ANSI): 
11 West 42nd Street, New York, NY 1036 

ANSI C57. 

Lead markings of large transformers 

American Society for Testing and Materials (ASTM): 
1916 Race Street, Philadelphia, PA 191034187 

ASTM D-887 

Test for dielectric strength of oil 

ASTM D-924 

Test of oil power factor 

ASTM D-971 

Test of oil film strength 

ASTM D-974 

Test for contaminants in oil 

ASTM D-1500 
Test of oil color 

ASTM D-1533 

Test of moisture content in oil 

ASTM D-1816 

Test for dielectric strength of oil above 230 KV 

ASTM B-2285 

Test of oil film strength using a different method than ASTM D-971 



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TM 5-686 



GLOSSARY 



Section I 
Abbreviations 

A, AMP 

amperes 

AC 

alternating current 

ANSI 

American National Standards Institute 

ASTM 

American Society for Testing Material 

BIL 

basic impulse level 

C 

Centigrade 

CFM 

cubic feet per minute 

DC 

direct current 

F 

Fahrenheit 

Hz 

hertz 

IEEE 

Institute of Electrical and Electronics Engineers 

1R 

infrared 

kV 

kilo volts 

kVA 

kilo volt amperes 

kVAR, kilovars 

kilo volt amperes reactance 

kW 

kilo watts 

Milliampere 

1 millionth of an ampere 

Megohm 

1 million ohms 

Milliohm 

1 millionth of an ohm 



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NEC 

National Electrical Code 

NEMA 

National Electrical Manufacturers Association 

NFPA 

National Fire Protection Association 

PCB 

polycholorinated biphenyls 

PF 

power factor 

pH 

pouvior hydrogene 

PPM 

parts per million 

PSI 

pounds per square inch 

PT 

potential transformer 

V 

volt 

VAR 

volt amperes reactance 

W 

watt 

A, AMP 

amperes 



Section II 
Terms 

AA 

An Ansi (American National Standard Institute) cooling class designation indicating open, natural-draft ventilated 
transformer construction, usually for dry-type transformers. 

Ambient Temperature 

The temperature of the surrounding atmosphere into which the heat of the transformer is dissipated. 

Ampere 

Unit of current flow. 

ANSI (American National Standards Institute) 

An organization that provides written standards on transformer [600v and below (ANSI C89.1), 60 lv and above 
(ANSI C57.12)]. 

Autotransformer 

A transformer in which part of the winding is common to both the primary and the secondary circuits. 

BIL 

Basic Impulse Level, the crest (peak) value that the insulation is required to withstand without failure. 

Bushing 

An electrical insulator (porcelain, epoxy, etc.) that is used to control the high voltage stresses that occur when an 
energized cable must pass through a grounded barrier. 

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Cast-coil Transformer 

A transformer with high-voltage coils cast in an epoxy resin. Usually used with 5 to 15 kV transformers. 

Continuous Rating 

Defines the constant load that a transformer can carry at rated primary voltage and frequency without exceeding the 
specified temperature rise. 

Copper Losses 

See Load Losses. 

Core-Form Construction 

A type of core construction where the winding materials completely enclose the core. 

Current Transformer 

A transformer generally used in instrumentation circuits that measure or control current. 

Delta 

A standard three-phase connection with the ends of each phase winding connected in series to form a closed loop 
with each phase 120 degrees from the other. Sometimes referred to as 3-wire. 

Delta Wye 

A term or symbol indicating the primary connected in delta and the secondary in wye when pertaining to a three- 
phase transformer or transformer bank. 

Distribution Transformers 

Those rated 5 to 120 kV on the high-voltage side and normally used in secondary distribution systems. An aplicable 
standard is ANSI C-57.12. 

Dripproof 

Constructed or protected so that successful operation is not interfered with by falling moisture or dirt. 

Dry-Type 

A transformer in which the transformer core and coils are not immresed in liquid. 

Exciting Current (No-load Current) 

Current that flows in any winding used to excite the transformer when all other windings are open-circuited. It is 
usually expressed in percent of the rated current of a winding in which it is measued. 

FA 

An ANSI cooling class designation indicating a forced air ventilated transformer, usually for dry type transformers 
and typically to increae the transformers and typically to increase the transformer's KVA rating above the natural 
ventilation or AA rating. 

Fan Cooled 

Cooled mechanically to stay within rated temperature rise by additino of fans internally and/or externally. Normally 
used on large transformers only. 

FOA 

An ANSI cooling class designation indicating forced oil cooling using pumps to circulate the oil for increased cool- 
ing capacity. 

FOW 

An ANSI cooling class designation indicating forced oil water cooling using a separate water loop in the oil to take 
the heat to a remote heat exchanger. Typically used where air cooling is difficult such as underground. 

Frequency 

On AC circuits, designate number of times that polarity alternates from positive to negative and back again, such as 
60 hertz (cycles per second). 

Grounds or Grounding 

Connecting one side of a circuit to the earth through low-resistance or low-impedance paths. This help prevent 
transmitting electrical shock to personnel. 

High-voltage and Low-voltage Windings 

Terms used to distinguish the wind that has the greater voltage rating from that having the lesser in two-winding 

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transformers. The terminations on the high-voltage windings are identified by HI, H2, etc., and on the low-voltage 
by XI, X2, , etc. 

Impedance 

Retarding forces of current flow in AC circuits. 

Indoor Transformer 

A transformer that, because of its construction, is not suitable for outdoor service. 

Insulating Materials 

Those materials used to electrically insulate the transformer windings from each other and to ground. Usually clas- 
sified by degree of strength or voltage rating (O, A, B, C, and H). 

kVA or Volt-ampere Output Rating 

The kVA or volt-ampere output rating designates the output that a transformer can deliver for a specified time at 
rated secondary voltage and rated frequency without exceeding the specified temperature rise (1 kVA = 1000 VA). 

Liquid-immersed Transformer 

A transformer with the core and coils immersed in liquid (as opposed to a dry-type transformer). 

Load 

The amount of electricity, in kVA or volt-amperes, supplied by the transformer. Loads are expressed as a function of 
the current flowing in the transformer, and not according to the watts consumed by the equipment the transformer 
feeds. 

Load Losses 

Those losses in a transformer that are incident to load carrying. Load losses include the I 2 R loss in the winding, core 
clamps, etc., and the circulating currents (if any) in parallel windings. 

Mid-tap 

A reduced-capacity tap mid-day in a winding — usually the secondary. 

Moisture-resistant 

Constructed or treated so as to reduce harm by exposure to a moist atmosphere. 

Natural-draft or Natural-draft Ventilated 

An open transformer cooled by the draft created by the chimney effect of the heated air in its enclosure. 

No-load Losses (Excitation Losses) 

Loss in a transformer that is excited at its rated voltage and frequency, but which is not supplying load. No-load loss- 
es include core loss, dielectric loss, and copper loss in the winding due to exciting current. 

OA 

An ANSI cooling class designation indicating an oil filled transformer. 

Parallel Operation 

Single and three-phase transformers having appropriate terminals may be operated in parallel by connecting simi- 
larly-marked terminals, provided their ratios, voltages, resistances, reactances, and ground connections are 
designed to permit paralleled operation and provided their angular displacements are the same in the case of three- 
phase transformers. 

Polarity Test 

A standard test performed on transformers to determine instantaneous direction of the voltages in the primary com- 
pared to the secondary (see Transformer Tests). 

Poly-phase 

More than one phase. 

Potential (Voltage) Transformer 

A transformer used in instrumentation circuits that measure or control voltage. 

Power Factor 

The ratio of watts to volt-amps in a circuit. 

Primary Taps 

Taps added in the primary winding (see Tap). 

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Primary Voltage Rating 

Designates the input circuit voltage for which the primary winding is designed. 

Primary Winding 

The primary winding on the energy input (supply) side. 

Rating 

The output or input and any other characteristic, such as primary and secondary voltage, current, frequency, power 
factor and temperature rise assigned to the transformer by the manufacturer. 

Ratio Test 

A standard test of transformers used to determine the ratio of the primary to the secondary voltage. 

Reactance 

The effect of inductive and capacitive components of the circuit producing other than unity power factor. 

Reactor 

A device for introducing inductive reactance into a circuit for motor starting, operating transformers in parallel, and 
controlling current. 

Scott Connection 

Connection for polyphase transformers. Usually used to change from two-phase to three-phase to three-phase to 
two-phase. 

Sealed Transformer 

A transformer completely sealed from outside atmosphere and usually contains an inert gas that is slightly pressur- 
ized 

Secondary Taps 

Taps located in the secondary winding (see Tap). 

Secondary Voltage Rating 

Designates the load-circuit voltage for which the secondary winding (winding on the output side) is designed. 

Series/Multiple 

A winding of two similar coils that can be connected for series operation or multiple (parellel) operation. 

Shell-type Construction 

A type of transformer construction where the core completely surrounds the coil. 

Star Connection 

Same as wye connections. 

Step-down Transformer 

A transformer in which the energy transfer is from the high-voltage winding to the low-voltage winding or windings. 

Step-up Transformer 

A transformer in which the energy transfer is from the low-voltage winding to a high-voltage winding or windings. 

T-Connection 

Use of Scott Connection for three-phase operation. 

Tap 

A connection brought out of a winding at some point between its extremities, usually to permit changing the volt- 
age or current ratio. 

Temperature Rise 

The increase over ambient temperature of th winding due to energizing and loading the transformer. 

Total Losses 

The losses represented by the sum of the no-load and the load losses. 

Transformer 

An electrical device, without continuously moving parts, which, by electro-magnetic induction, transforms energy 
from one or more circuits to other circuits at the same frequency, usually with changed values of voltage and cur- 
rent. 



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Ttarns Ratio (of a transformer) 

The ratio of turns in the primary winding to the number of turns in the secondary winding. 

Volt-amperes 

Circuit volts multiplied by circuit amperes. 

Voltage Ratio (of a transformer) 

The ratio of the RMS primary terminal voltage to the RMS secondary terminal voltage under specified conditions of 
load. 

Voltage Regulation (of a transformer) 

The change in secondary voltage that occurs when the load is reduced from rated value to zero, with the values of 
all other quantities remaining unchanged. The regulation may be expressed in percent (or per unit) on the basis of 
the rated secondary voltage at full load. 

Winding Losses 
See Load Losses. 

Winding Voltage Rating 

Designates the voltage for which the winding is designed. 

Wye Connection (Y) 

A standard three-phase connection with similar ends of the single-phase coils connected to a common point. This 
common point forms the electrical neutral point and may be grounded. 



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TM 5-686 



The proponent agency of this publication is the Chief of Engineers, United States Army. Users are 
invited to send comments and suggested improvements on DA Form 2028 (Recommended Changes 
to Publications and Blank Forms) directly to HQUSACE, (ATTN: CECPW-EE), Washington, DC 
20314-1000. 



By Order of the Secretary of the Army: 

DENNIS J. REIMER 
General, United States Army 
Official: Chief of Staff 



WOEL B. HUDSON 
Administrative Assistant to the 
Secretary of the Army 



Distribution: 
To be distributed in accordance with Initial Distribution Number (IDN), 344686, requirements for TM 5-686.